Methods and systems to control flow and heat transfer between subsurface wellbores connected hydraulically by fractures

ABSTRACT

A controlled rate of propagation of the fluid saturation front or thermal front is desired in may oil and gas and geothermal operations. Natural fractures and fractures created during hydraulic stimulation may have heterogeneous hydraulic properties resulting in uneven flow distributions, therefore leading to short-circuiting and breakthrough issues. The present invention relates to wellbores connected hydraulically by multiple fracture zones; methods are directed to control for even flow distribution among fractures, regardless of heterogeneities in fracture hydraulic properties, and to control propagation of saturation fronts and thermal fronts in subsurface reservoirs.

This application: (i) claims benefit of priority to and claims under 35U.S.C. § 119(e)(1) the benefit of the filing date of U.S. provisionalapplication Ser. No. 62/764,835 filed Aug. 16, 2018; and, (ii) claimsbenefit of priority to and claims under 35 U.S.C. § 119(e)(1) thebenefit of the filing date of U.S. provisional application Ser. No.62/764,837 filed Aug. 16, 2018, the entire disclosures of each of whichare incorporated herein by reference.

BACKGROUND OF THE INVENTION Field of the Invention

The present invention relates to systems, methods and operations forenhancing the recovery of resources from within the ground. Inparticular, embodiments of the present inventions relate to novelsystems and operations to alter, modify and change subterraneanformations to enhance the recovery of resources from those formations.Embodiments of the present inventions relate to the recovery ofsubsurface resources, such as minerals, ores, gems, metals, water andenergy sources including hydrocarbon and geothermal. Embodiments of thepresent inventions further relate to real-time adjustments to hydraulicstimulation treatments.

Typically, in the production of natural resources from formations withinthe earth a well or borehole is drilled into the earth to the locationwhere the natural resource is believed to be located. These naturalresources may be a heat source for geothermal energy, a hydrocarbonreservoir, containing natural gas, crude oil and combinations of these;the natural resource may be fresh water; or it may be some other naturalresource that is located within the ground.

These resource-containing formations may be a few hundred feet, a fewthousand feet, or tens of thousands of feet below the surface of theearth, including under the floor of a body of water, e.g., below the seafloor. In addition to being at various depths within the earth, theseformations may cover areas of differing sizes, shapes and volumes.

Unfortunately, and generally, when a well is drilled into theseformations the natural resources rarely flow into and out of theformation, and into the well at rates, durations and amounts that areeconomically viable. This problem occurs for several reasons, some ofwhich are well understood, others of which were not as well understood,some of which may not yet be known, and several of which, prior to thepresent inventions were incorrect. These problems can relate to theviscosity of the natural resource, the porosity of the formation, thegeology of the formation, the formation pressures, and the perforationsthat place the production tubing in the well in fluid communication withthe formation, to name a few.

Thermal Breakthrough—Long Standing Problem

Early or premature thermal breakthrough has been observed at manyhydrothermal and enhanced geothermal sites around the world, includingThe Geysers in the United States, Beowawe in the United States,Miravalles in Costa Rica, Cerro Prieto in Mexico, Hijiori Hot Dry Rocktest site in Japan, and Rosemanowes in the United Kingdom. A review ofgeothermal projects in the United States found that declines inproduction temperature are most commonly attributed to short-circuitingthrough high permeability faults and fractures (as opposed to undulyclose spacing between injection and production wells) (Sanyal, S. etal., 1995). A worldwide review of reinjection strategies at geothermalfields found that reinjection caused thermal breakthrough to occur atproduction wells within ten years at 31 different sites (Kaya et al.,2011). Premature thermal breakthrough behavior has been observed acrossall types of geothermal reservoirs, including low and medium-enthalpywater dominated systems, medium enthalpy two-phase systems, andhigh-enthalpy two-phase systems (Kaya et al., 2011).

Several fluid circulation tests were performed in deep geothermal wellsat the Hijiori Hot Dry Rock test site in Japan from 2000 to 2001 (Tenmaet al., 2008). One test (called Run Segment 3) involved injection intotwo wells and production from two offset wells. Injection rates rangedfrom roughly 4 kg/s to 12 kg/s, and production rates ranged from roughly2 kg/s to 10 kg/s per well. Over approximately 90 days, one of theproduction wells, HDR-2a, experienced significant thermal drawdown. Thewellhead temperature in production well HDR-2a dropped from 180° C. to120° C. over roughly a 1-month period, and then dropped an additional20° C. over the remainder of the circulation experiment. This severelevel of thermal drawdown would not support long-term power generationat economic levels.

Benoit and Stock (1993) recorded declines in production temperatures fortwo wells at the Beowawe, Nev., USA geothermal field, where temperaturesdropped from 420° F. to 375° F. and 420° F. to 400° F. over a five-yearperiod from 1987 to 1992. Tracer tests showed quick breakthrough timeson the order of 14 days.

At Rosemanowes, MacDonald, P., Stedman, A., and Symons, G., The UKgeothermal hot dry rock R&D programme. Paper presented at theSeventeenth Workshop on Geothermal Reservoir Engineering, Stanford,Calif., USA, 29-31 Jan. 1992) (“MacDonald et al. (1992)”), observed that“the thermal behavior of the heat exchanger was unsatisfactory (becauseof excessive temperature drawdown and short circuiting).” Duringcirculation experiments, injection rates of roughly 24 kg/s andproduction rates of about 19 kg/s were achieved (water losses wereobserved to be 21%). The production temperature dropped from 80° C. to55° C. over a three-year period from 1985 to 1988. Tracer testing showedevidence for the presence of a high permeability short-circuit pathwaybetween the injection and production boreholes. In addition, MacDonaldet al. (1992) made the following comments based on the Rosemanowes fieldproject:

“Flow through the underground system at Rosemanowes had been dominatedby the effects of short circuits. These effects were an inevitableconsequence of geological heterogeneity and therefore would be a featureof any stimulated rock mass. Successful operation of an HDR (hot dryrock) system would depend on exploitation and management of these shortcircuits,” and that “a satisfactory method for sealing short circuits,other than by mechanical sealing of the production wellbore has not yetbeen demonstrated.” MacDonald et al. (1992)

A 55 MW power station at Miravalles, Costa Rica, began operations inMarch 1994 (Parini et al., 1996). Over the first few months ofproduction, an increase in chloride concentrations was measured, whichthe operator attributed to rapid return of reinjected water. A tracertest was subsequently performed and indicated rapid breakthrough ofroughly 30 to 40 days. Numerical modeling calibrated against the tracertests results indicated risk of significant long term cooling theresults show up to a 10% reduction in production fluid energy contentover a 30-year period.

A reservoir-scale temperature decline of roughly 10° C. occurred over a14-year period at Cerro Prieto, in part due to cold water reinjection(Lippman et al., 2004).

Timing of Multistage Stimulations

Multistage hydraulic stimulation treatments are typically performed witha pumping schedule that is replicated across all stages. For example, aslickwater treatment may involve first pumping a pad of freshwater at arelatively low flow rate to initiate fracture propagation from eachcluster. Then, the injection rate may be increased, and the proppantconcentration may be increased over short steps until the designedproppant concentration is met. Pumping may continue for the designedstage duration, after which freshwater is pumped to flush any proppantremaining in the wellbore into the formation. The same pumping scheduleis repeated in each subsequent stage.

Minifrac, leakoff, extended leakoff, or diagnostic fracture injectiontests are typically performed during drilling or directly afterinstalling casing to determine the magnitude of the minimum principalstress; these tests are typically not performed on every well. Wellborebreakouts and drilling induced tensile fractures can be used to estimatethe magnitude of the maximum principal stress when caliper logs orwellbore image logs have been performed. Distributed acoustic sensingand distributed temperature sensing fiber optic measurements can be usedto evaluate cluster efficiency, but this type of analysis is typicallyperformed after the treatment has been completed. Pressure transientanalysis is commonly performed to evaluate the formation propertiesafter the completion phase, prior to setting the well on production;these tests are typically not performed for every well.

These prior techniques have many failings, including limitedapplicability based upon well type and problem, other adverse orunexpected results, cost, potential for lost production time,inoperability, limited success rates (both qualitative andquantitative). Thus, for these and other reasons they have not meet thelong standing need for enhanced and greater efficiency in thehydraulically stimulating, including hydraulically fracturing,formations for the recovery of resources from the earth, such asgeothermal, hydrocarbons, and minerals.

Related Art and Terminology

Typically, and by way of general illustration, in drilling a well aninitial borehole is made into the earth, e.g., the surface of land orseabed, and then subsequent and smaller diameter boreholes are drilledto extend the overall depth of the borehole. In this manner as theoverall borehole gets deeper its diameter becomes smaller; resulting inwhat can be envisioned as a telescoping assembly of holes with thelargest diameter hole being at the top of the borehole closest to thesurface of the earth.

Typically, when completing a well, it is necessary to perform aperforation operation. In general, when a well has been drilled andcasing, e.g., a metal pipe, is run to the prescribed depth, the casingis typically cemented in place by pumping cement down and into theannular space between the casing and the earth. (It is understood thatmany different down hole casing, open hole, and completion approachesmay be used.) The casing, among other things, prevents the hole fromcollapsing and fluids from flowing between permeable zones in theannulus. Thus, this casing forms a structural support for the well and abarrier to the earth.

While important for the structural integrity of the well, the casing andcement present a problem when they are in the production zone. Thus, inaddition to holding back the earth, they also prevent the resources orfluid from flowing into and out of the well and from being recovered.Additionally, the formation itself may have been damaged by the drillingprocess, e.g., by the pressure from the drilling mud, and this damagedarea of the formation may form an additional barrier to the flow ofresources. Similarly, in most situations where casing is not needed inthe production area, e.g., open hole, the formation itself is generallytight, and more typically can be very tight, and thus, will not permitthe flow of resources into and out of the well.

To address, in part, this problem of the flow of resources e.g.,geothermal, hydrocarbons, etc. into the well being blocked by thecasing, cement and the formation itself, openings, e.g., perforations,are made in the well in the area of the pay zone. Generally, aperforation is a small, about ¼″ to about 1″ or 2″ in diameter hole thatextends through the casing, cement and damaged formation and goes intothe formation. The holes can extend from the borehole wall into theformation from about 1″ to about 18″, about 3″ to about 10″, about 4″ to6″, about 3″ to about 8″, about 6″ to about 12″ and combinations andvariations of these, as well as, longer and smaller distances. This holecreates a passage for the resource to flow from the formation into thewell. In a typical well, a large number of these holes are made throughthe casing and into the formation in the pay zone.

As used herein, unless expressly stated otherwise, the term“perforations” and “perf” and “perforating” and similar such termsshould be given their broadest possible meaning and would include anyhole or opening formed in a borehole wall, casing, or other surface thatprovides fluid communication between the formation and the borehole.Generally, in a perforating operation a perforating tool or gun islowered into the borehole to the location where the production zone orpay zone is located. The perforating gun is a long, typically roundtool, that has a small enough diameter to fit into the casing or tubularand reach the area within the borehole where the production zone isbelieved to be. Once positioned in the production zone a series ofexplosive charges, e.g., shaped charges, are ignited. The hot gases andmolten metal from the explosion cut a hole, i.e., the perf orperforation, through the casing and into the formation. Theseexplosive-made perforations extend a few inches, e.g., 6″ to 18″ intothe formation. Perforations may also be made by other systems, such aslasers, or any other device or system that places holes in the tubular,the borehole wall, the formation, and combinations and variations ofthese.

Prior to the present inventions, geothermal well completions typicallyinvolved open-hole or slotted-liner completions in the productioninterval, and the use of cased and cemented boreholes were disfavoredfor geothermal wells and systems. Because permeability in geothermalreservoirs is typically limited to flow along a small number offractures or faults that act as hydraulically conductive pathways, casedand cemented wellbore completion designs were discredited based on theconcept that they would cause irreconcilable formation damage that wouldseal off the permeable fractures. However, open-hole and slotted linercompletions present many problems and limitations in terms of the toolsand techniques that can be employed downhole. Embodiments of the presentinventions go against this established thinking of the art, and usecased and cemented geothermal completion design, which enables the useof modified, additional and new techniques and in geothermalapplications, such as multistage, multicluster hydraulic fracturetreatments and proppant to be used in geothermal settings.

Prior to embodiments of the present inventions, it was believed that thegoals and purpose of hydraulic fracturing, e.g., to get as much of thenatural resource, i.e., oil or gas, out of the well as quickly aspossible were believed to be antagonist to, and counterproductive to,the goals and objectives of geothermal systems and wells. Embodiments ofthe present inventions go against these established thinking of the art.As discussed in greater detail in this specification, geotherm wellsrequire management of the geothermal heat source, and the avoidance ofthermal breakthrough, which can be detrimental, damaging, and at timescatastrophic, to the heat recovery efficiency and long-termsustainability of a geothermal energy recovery system. It is believedthat the present inventions are the first to recognize and develop asolution to these and other thermal management problems, includingthermal break through problems, that have been a long standing andongoing problem in geothermal systems, through the utilization of thespecific workover techniques, perforation patterns, hydraulic fracturingand proppant techniques, well designs, methods, and the resulting wellsand systems, of the present inventions.

As used herein, unless specified otherwise, the term “earth” should begiven its broadest possible meaning, and includes, the ground, allnatural materials, such as rocks, and artificial materials, such asconcrete, that are or may be found in the ground, including withoutlimitation rock layer formations, such as, granite, basalt, sandstone,dolomite, sand, salt, limestone, rhyolite, quartzite and shale rock.

As used herein, unless specified otherwise, the term “borehole” shouldbe given it broadest possible meaning and includes any opening that iscreated in a material, a work piece, a surface, the earth, a structure(e.g., building, protected military installation, nuclear plant,offshore platform, or ship), or in a structure in the ground, (e.g.,foundation, roadway, airstrip, cave or subterranean structure) that issubstantially longer than it is wide, such as a well, a well bore, awell hole, a micro hole, slimhole, a perforation and other termscommonly used or known in the arts to define these types of narrow longpassages. Wells would further include exploratory, production,abandoned, reentered, reworked, and injection wells. Although boreholesare generally oriented substantially vertically, they may also beoriented on an angle from vertical, to and including horizontal. Thus,using a vertical line, based upon a level as a reference point, aborehole can have orientations ranging from 0° i.e., vertical, to 90°,i.e., horizontal and greater than 90° e.g., such as a heel and toe andcombinations of these such as for example “U” and “Y” shapes. Boreholesmay further have segments or sections that have different orientations,they may have straight sections and arcuate sections and combinationsthereof; and for example, may be of the shapes commonly found whendirectional drilling is employed. Thus, as used herein unless expresslyprovided otherwise, the “bottom” of a borehole, the “bottom surface” ofthe borehole and similar terms refer to the end of the borehole, i.e.,that portion of the borehole furthest along the path of the boreholefrom the borehole's opening, the surface of the earth, or the borehole'sbeginning. The terms “side” and “wall” of a borehole should to be giventheir broadest possible meaning and include the longitudinal surfaces ofthe borehole, whether or not casing or a liner is present, as such,these terms would include the sides of an open borehole or the sides ofthe casing that has been positioned within a borehole. Boreholes may bemade up of a single passage, multiple passages, connected passages andcombinations thereof, in a situation where multiple boreholes areconnected or interconnected each borehole would have a borehole bottom.Boreholes may be formed in the sea floor, under bodies of water, onland, in ice formations, or in other locations and settings.

Boreholes are generally formed and advanced by using mechanical drillingequipment having a rotating drilling tool, e.g., a bit. For example, andin general, when creating a borehole in the earth, a drilling bit isextending to and into the earth and rotated to create a hole in theearth. In general, to perform the drilling operation the bit must beforced against the material to be removed with a sufficient force toexceed the shear strength, compressive strength or combinations thereof,of that material. Thus, in conventional drilling activity mechanicalforces exceeding these strengths of the rock or earth must be applied.The material that is cut from the earth is generally known as cuttings,e.g., waste, which may be chips of rock, dust, rock fibers and othertypes of materials and structures that may be created by the bit'sinteractions with the earth. These cuttings are typically removed fromthe borehole by the use of fluids, which fluids can be liquids, foams orgases, or other materials know to the art.

As used herein, unless specified otherwise, the term “advancing” aborehole should be given its broadest possible meaning and includesincreasing the length of the borehole. Thus, by advancing a borehole,provided the orientation is not horizontal, e.g., less than 90° thedepth of the borehole may also be increased. The true vertical depth(“TVD”) of a borehole is the distance from the top or surface of theborehole to the depth at which the bottom of the borehole is located,measured along a straight vertical line. The measured depth (“MD”) of aborehole is the distance as measured along the actual path of theborehole from the top or surface to the bottom. As used herein unlessspecified otherwise the term depth of a borehole will refer to MD. Ingeneral, a point of reference may be used for the top of the borehole,such as the rotary table, drill floor, well head or initial opening orsurface of the structure in which the borehole is placed.

As used herein, unless specified otherwise, the terms “workover,”“completion” and “workover and completion” and similar such terms shouldbe given their broadest possible meanings and would include activitiesthat place at or near the completion of drilling a well, activities thattake place at or the near the commencement of production from the well,activities that take place on the well when the well is producing oroperating well, activities that take place to reopen or reenter anabandoned or plugged well or branch of a well, and would also includefor example, perforating, cementing, acidizing, fracturing, pressuretesting, the removal of well debris, removal of plugs, insertion orreplacement of production tubing, forming windows in casing to drill orcomplete lateral or branch wellbores, cutting and milling operations ingeneral, insertion of screens, stimulating, cleaning, testing, analyzingand other such activities. These terms would further include applyingheat, directed energy, preferably in the form of a high power laser beamto heat, melt, soften, activate, vaporize, disengage, desiccate andcombinations and variations of these, materials in a well, or otherstructure, to remove, assist in their removal, cleanout, condition andcombinations and variation of these, such materials.

As used herein, unless specified otherwise, the terms “formation,”“reservoir,” “pay zone,” “production zone” and similar terms, are to begiven their broadest possible meanings and would include all locations,areas, and geological features within the earth that contain, maycontain, or are believed to contain, a natural resource, e.g.,geothermal energy, hydrocarbons, etc.

Generally, the term “about” and the symbol “˜” as used herein unlessstated otherwise is meant to encompass a variance or range of ±10%, theexperimental or instrument error associated with obtaining the statedvalue, and preferably the larger of these.

As used herein unless specified otherwise, the recitation of ranges ofvalues herein is merely intended to serve as a shorthand method ofreferring individually to each separate value falling within the range.Unless otherwise indicated herein, each individual value within a rangeis incorporated into the specification as if it were individuallyrecited herein.

As used herein, unless specified otherwise, the terms “geothermal”,“geothermal well”, “geothermal resource”, “geothermal energy” andsimilar such terms, should be given their broadest possible meaning andincluding wells, systems and operations that recover or utilize the heatenergy that is contained within the earth. Such systems and operationswould include enhanced geothermal well, engineered geothermal wells,binary cycle power plants, dry steam power plants, flash steam powerplants, open looped systems, and closed loop systems.

As used herein, unless specified otherwise, the terms “field,” “oilfield” “geothermal field” and similar terms, are to be given theirbroadest possible meanings, and would include any area of land, seafloor, or water that is loosely or directly associated with a formation,and more particularly with a resource containing formation, thus, afield may have one or more exploratory and producing wells associatedwith it, a field may have one or more governmental body or privateresource leases associated with it, and one or more field(s) may bedirectly associated with a resource containing formation.

As used herein, unless specified otherwise, the terms “conventionalgas”, “conventional oil”, “conventional”, “conventional production” andsimilar such terms are to be given their broadest possible meaning andinclude hydrocarbons, e.g., gas and oil, that are trapped in structuresin the earth. Generally, in these conventional formations thehydrocarbons have migrated in permeable, or semi-permeable formations toa trap, or area where they are accumulated. Typically, in conventionalformations a non-porous layer is above, or encompassing the area ofaccumulated hydrocarbons, in essence trapping the hydrocarbonaccumulation. Conventional reservoirs have been historically the sourcesof the vast majority of hydrocarbons produced. As used herein, unlessspecified otherwise, the terms “unconventional gas”, “unconventionaloil”, “unconventional”, “unconventional production” and similar suchterms are to be given their broadest possible meaning and includeshydrocarbons that are held in impermeable rock, and which have notmigrated to traps or areas of accumulation.

As used herein, unless specified otherwise, the terms “hydrocarbonexploration and production”, “exploration and production activities”,“E&P”, and “E&P activities”, and similar such terms are to be giventheir broadest possible meaning, and include surveying, geologicalanalysis, well planning, reservoir planning, reservoir management,drilling a well, workover and completion activities, hydrocarbonproduction, flowing of hydrocarbons from a well, collection ofhydrocarbons, secondary and tertiary recovery from a well, themanagement of flowing hydrocarbons from a well, and any other upstreamactivities.

As used herein, unless specified otherwise, the terms “poroelastic”,“poroelasticity”, “poroelastic stresses”, “poroelastic forces” andsimilar such terms should be given their broadest possible meanings andwould include the forces, stresses and effects that are based upon theinteraction between fluid flow and solid deformation within a porousmedium. Typically, in evaluating poroelastic effects Darcy's law, whichdescribes the relation between fluid motion and pressure within a porousmedium, is coupled with the structural displacement of the porousmatrix.

The ability of, or ease with which, the natural resource can flow out ofthe formation and into the well or production tubing (into and out of,for example, in the case of engineered geothermal wells, and someadvanced recovery methods for hydrocarbon wells) can generally beunderstood as the fluid communication between the well and theformation. As this fluid communication is increased several enhancementsor benefits may be obtained: the volume or rate of flow (e.g., gallonsper minute) can increase; the distance within the formation out from thewell where the natural resources will flow into the well can be increase(e.g., the volume and area of the formation that can be drained by asingle well is increased, and it will thus take less total wells torecover the resources from an entire field); the time period when thewell is producing resources can be lengthened; the flow rate can bemaintained at a higher rate for a longer period of time; andcombinations of these and other efficiencies and benefits.

Fluid communication between the formation and the well can be increasedby the use of hydraulic stimulation techniques. The first uses ofhydraulic stimulation date back to the late 1940s and early 1950s. Ingeneral, hydraulic treatments involve forcing fluids down the well andinto the formation, where the fluids enter the formation and crack,e.g., force the layers of rock to break apart or fracture. Thesefractures create channels or flow paths that may have cross sections ofa few micron's, to a few millimeters, to several millimeters in size,and potentially larger. The fractures may also extend out from the wellin all directions for a few feet, several feet and tens of feet orfurther. It should be remembered that the longitudinal axis of the wellin the reservoir may not be vertical: it may be on an angle (eitherslopping up or down) or it may be horizontal. The section of the welllocated within the reservoir, i.e., the section of the formationcontaining the natural resources, can be called the pay zone.

Typical fluid volumes in a propped fracturing treatment of a formationin general can range from a few thousand to a few million gallons.Proppant volumes can approach several thousand cubic feet. In general,the objective of a proppant fracturing in hydrocarbon wells is to createand enhance fluid communication between the wellbore and thehydrocarbons in the formation, e.g., the reservoir. Thus, proppantfracturing techniques are used to create and enhance conductive pathwaysfor the hydrocarbons to get from the reservoir to the wellbore. Further,a desirable way of enhancing the efficacy of proppant fracturingtechniques is to have uniform proppant distribution. In this manner auniformly conductive fracture along the wellbore height and fracturehalf-length can be provided. However, the complicated nature of proppantsettling, and in particular in non-Newtonian fluids often causes ahigher concentration of proppant to settle down in the lower part of thefracture. This in turn can create a lack of adequate proppant coverageon the upper portion of the fracture and the wellbore. Clustering ofproppant, encapsulation, bridging, crushing and embedment are a fewnegative occurrences or phenomena that can lower the potentialconductivity of the proppant pack, and efficacy of hydraulic fractureand the well.

The fluids used to perform hydraulic fracture can range from verysimple, e.g., water, to very complex. Additionally, these fluids, e.g.,fracing fluids or fracturing fluids, typically carry with themproppants; but not in all cases, e.g., when acids are used to fracturecarbonate formations. Proppants are small particles, e.g., grains ofsand, aluminum shot, sintered bauxite, ceramic beads, resin coated sandor ceramics, that are flowed into the fractures and hold, e.g., “prop”or hold open the fractures when the pressure of the fracturing fluid isreduced and the fluid is removed to allow the resource, e.g.,hydrocarbons, to flow into the well.

In this manner the proppants hold open the fractures, keeping thechannels open so that the hydrocarbons can more readily flow into thewell. Additionally, the fractures greatly increase the surface area fromwhich the hydrocarbons can flow into the well.

Typically fracturing fluids consist primarily of water but also haveother materials in them. The number of other materials, e.g., chemicaladditives used in a typical fracture treatment varies depending on theconditions of the specific well that is being fractured. Generally, atypical fracture treatment will use from about 2 to about 25 additives.

Generally, the predominant fluids being used for fracture treatments inthe shale formations are water-based fracturing fluids mixed withfriction-reducing additives, e.g., slick water, or slick water fracs.Overall the concentration of additives in most slick water fracturingfluids is generally about 0.5% to 2% with water and sand making up 98%to 99.5% by weight. The addition of friction reducers allows fracturingfluids and proppant to be pumped to the target zone at a higher rate andreduced pressure than if water alone were used.

Although hydraulic stimulation has been used in geothermal wells, theuse of proppants has generally not been used, and its use has beendiscredited by those in the art.

Generally, in prior geothermal wells, even those that have beenhydraulically stimulated, the performance and efficiency of the well,and geothermal power plant, has been less than desirable and suboptimal.Most importantly, geothermal fluid circulation rates have tended to betoo low to support commercial levels of power generation and thermalbreakthrough has tended to occur before the intended duration of projectlife. This suboptimal performance has hindered the adoption ofgeothermal energy, making its replace of hydrocarbon energy sourcesdifficult. This suboptimal performance has reduced the ability ofgeothermal energy, which is a clean, carbon free energy source, frombeing widely adopted and replacing carbon emitting, e.g., coal, oil,natural gas, power generation sources.

One of the reasons for this lack of efficiency, and suboptimalperformance of geothermal wells and plants is the lack of uniformity inthe formation containing the geothermal resource, e.g., the subterraneanhot rock. This heterogeneity is ubiquitous in the subsurface andrepresents a significant barrier toward successful design of a reservoirengineering strategy for optimal resource exploitation. Permeability canoften be described through a log-normal probability distributionfunction, suggesting that flow can become localized within a smallnumber of relatively high permeability zones. In subsurface systemswhere reservoir behavior is dominated by flow through fractures,heterogeneity in fracture permeability can result in poor oruncontrolled reservoir performance. For example, ‘thief zones’ can causebreakthrough during waterflood or enhanced oil recovery operations,effectively bypassing large volumes of trapped oil. In geothermalreservoirs, fracture zones that take high flow rates can cool relativelyquickly causing premature thermal breakthrough; moreover, thermalstresses generated by cooling in these high-flow pathways tend tofurther increase the zone's permeability contributing to apositive-feedback loop.

A prior technique to address heterogeneity issues, and which has notproved effective is the use of liners, plugs and other zonal isolationtechnologies, to attempt to address and control flow of fluids throughthe formation. During production, scab liners are used to isolatebreaches in casing or ineffective perforations. During hydraulicstimulation, perforation clusters are designed to distribute flow amongseveral fractures within a single stage based on the limited entryperforation pressure drop effect; these designs ensure uniform fracturepropagation from a single well within each individual treatment stage,and the cluster design is typically replicated for all stages. Chemicaldiverters have been used in geothermal wells with open-hole or slottedliner completions to temporarily screen out high-permeability pathwaysand to divert flow towards stimulating less permeable pathways. Downholeinstruments can be used to control flow rates in various sections ofwellbores, but these are often expensive systems, that have failed tofully address the problems with and inefficiencies of prior geothermalwells and plants.

As used herein, unless stated otherwise, room temperature is 25° C. And,standard ambient temperature and pressure is 25° C. and 1 atmosphere.Unless expressly stated otherwise all tests, test results, physicalproperties, and values that are temperature dependent, pressuredependent, or both, are provided at standard ambient temperature andpressure.

This Background of the Invention section is intended to introducevarious aspects of the art, which may be associated with embodiments ofthe present inventions. Thus, the forgoing discussion in this sectionprovides a framework for better understanding the present inventions,and is not to be viewed as an admission of prior art.

SUMMARY

There has been a long-standing and unfulfilled need for the reduction ofgreenhouse gasses; and, in particular, the emission of such gasses inthe production of energy, in particular electrical energy. Geothermalenergy production, although initially promising, has failed to meet thislong-standing need for clean energy production. A long standing andunsolved problem and cause of this failure is thermal breakthrough andshort-circuiting in geothermal energy systems. The present inventions,among other things, solve these needs and long standing problems byproviding the systems, materials, articles of manufacture, devices andprocesses taught, disclosed and claimed herein.

There has been a long-standing and unfulfilled need for the reduction ofgreenhouse gasses; and, in particular, the emission of such gasses inthe production of energy, in particular electrical energy. Geothermalenergy production, although initially promising, has failed to meet thislong-standing need for clean energy production. A long standing andunsolved problem and cause of this failure is the heterogeneity of theformation containing the geothermal resource, and the fractures in thatformation. The present inventions, among other things, solve these needsand long standing problems by providing the systems, materials, articlesof manufacture, devices and processes taught, disclosed and claimedherein.

The present inventions address, mitigate and overcome this long-standingproblem of thermal break through, short circuiting, and heterogeneity,among other problems with wells and subterranean resource recovery; andthus, provide enhanced and optimized geothermal wells and plants. Inturn, this provides the potential to greatly reduce the amount ofgreenhouse gasses, e.g., CO₂, associated with energy production.

The present inventions, among other things, solve these needs byproviding the systems, materials, articles of manufacture, devices andprocesses taught, disclosed and claimed herein.

A method of providing optimized recovery of geothermal energy for aformation while reducing thermal breakthrough, the method including:selecting a formation below the surface of the earth, the formationincluding a geothermal heat source; selecting a first well and a secondwell in the formation; wherein each well has a vertical section and anon-vertical section; hydraulically fracturing the formation by pumpinga fracturing fluid under pressures in excess of the fracture pressure ofthe formation through a plurality of perforations in a side wall in thenon-vertical section of the first well, the second well or both wells;whereby a substantially uniform tortuous flow path is establishedbetween the first well and the second well; wherein the substantiallyuniform tortuous flow path can transmit more than 40 Kg/s (kilograms offluid/second) of a heat recovery fluid from the first well to the secondwell.

Additionally, there is provided these methods, plans, wells and systemshaving one or more of the following features: wherein the plurality ofperforations have: a first stage having from 3 to about 20 perforations,and a second stage having from 3 to about 20 perforations; wherein thepumping pressure is less than 90% of the fracture pressure and the flowrate is from about 40 Kg/s to about 100 Kg/s; wherein the pumpingpressure is less than 90% of the fracture pressure and the flow rate isfrom about 40 Kg/s to about 100 Kg/s; wherein the plurality ofperforations have: a first stage having from 3 to about 20 perforations,and a second stage having from 3 to about 20 perforations, wherein thenumber of perforations in the second stage is different from the numberof perforations in the first stage; and, wherein the fracture fluid hasa proppant.

Still further, there is provided a limited entry perforation (LEP)geothermal energy system, the system including: a first well extendingfrom above a surface of the earth into the earth and into a formationcontaining a geothermal heat source; a second well extending from abovethe surface of the earth into the earth and into the formationcontaining a geothermal heat source defining a geothermal reservoir; thefirst well having a heel and a horizontal producing section, wherein thehorizontal producing section has a casing and extends into thegeothermal reservoir; the second well extending into the geothermalreservoir; a producing section of the first well including a pluralityof stages, wherein each stage has a plurality of perforations throughthe casing and into the geothermal reservoir; a plurality of fracturezones in the geothermal reservoir placing the stages of the first wellin fluid communication with the second well, at least one of thefracture zones associated with at least one of the stages of theproducing section of the first well; wherein the associated fracturezone defining a tortuous fluid flow path for a heat recovery fluidthrough the geothermal reservoir; and, whereby the configuration of theperforations and the fracture zones provide a substantially uniform flowpath between the producing section and the second well.

Moreover, there is provided these methods, plans, wells and systemshaving one or more of the following features: wherein the perforationsin at least one of the stages is zero phased; wherein the perforationsin at least one of the states is 60° phased; wherein the plurality ofperforations in each of the stages defines a cluster; wherein the firstwell is an injection well; wherein the fracture zones comprise aplurality of proppants; wherein the proppants define a proppant pack;wherein the proppants comprise microproppants; wherein the proppant packis a monolayer distribution of the proppant in the fractures; wherein amajority of each the fracture zones have a different flowcharacteristic; wherein the perforations in each of a majority of thestages define a flow different flow characteristic, whereby a majorityof the stages have a different flow characteristic; wherein thesubstantially uniform flow is characterized in part by having a flowacross at least 85% of the perforations that is uniform; wherein thesubstantially uniform flow is characterized in part by having a flowacross at least 85% of the perforations that is highly uniform; whereinthe substantially uniform flow is characterized in part by having a flowacross at least 85% of the stages that is uniform; wherein thesubstantially uniform flow is characterized in part by having a flowacross at least 85% of the stages that is highly uniform; wherein thesubstantially uniform flow is characterized in part by having a flowacross all of the stages that is uniform; wherein the substantiallyuniform flow is characterized in part by having a flow across all of thestages that is highly uniform; wherein the producing section defines alength and the substantially uniform flow is characterized in part byhaving a flow across at least 80% of the length of the producing sectionthat is uniform; wherein the producing section defines a length and thesubstantially uniform flow is characterized in part by having a flowacross at least 80% of the length of the producing section that ishighly uniform; wherein the substantially uniform flow is characterizedin part by a linear temperature front; and, wherein the substantiallyuniform flow is characterized in part by a linear temperature front overtime.

Still additionally, there is provided a well system for the recovery ofgeothermal energy, the system including: an injection well in ageothermal reservoir below a surface of the earth; a producing well inthe geothermal reservoir; a fluid flow path through the geothermalreservoir and placing the injection well and the producing well in fluidcommunication, whereby the system is configured to flow a heat recoveryfluid from the injection well through the reservoir and into theproducing well; the fluid flow path including a plurality of fracturezones, wherein a majority of the fracture zones have different flowcharacteristic; and, the injection well including a plurality of stages,wherein each of the stages has a predetermined perforation pattern,wherein the predetermined perforation pattern is based in part upon theflow characteristics of the fracture zones; whereby the system providesfor a uniform temperature front of a heat recovery fluid through thereservoir between the injection well and the production well.

Furthermore, there is provided a method to achieve even flow infractures distributed across two or more stages of a borehole havingvertical and horizontal sections, the method including: selecting ahorizontal section of a borehole in a reservoir containing a naturalresource; wherein the selected horizontal section defines a length andhas a series of hydraulic fracture treatment stages; defining aplurality of perforation clusters along the length of the selectedhorizontal section, wherein each perforation cluster has a series ofperforation holes that cause a friction pressure drop when fluid flowsthrough; optimizing the friction pressure drop across each clusterwithin an individual treatment stage based on the flow conditions duringthe hydraulic fracturing treatment; and optimizing the friction pressuredrop across each perforation cluster along multiple treatment stagesbased on the flow conditions during long-term operations.

In addition, there is provided a method to achieve even flow infractures distributed across two or more stages of a borehole havingvertical and horizontal sections, the method including: selecting ahorizontal section of a borehole in a reservoir containing a naturalresource; wherein the selected horizontal section defines a length andhas a series of hydraulic fracture treatment stages; defining aplurality of fractures or fracture zones that intersect the wellbore;optimizing a fluid additive to react with the reservoir material orproppant material to cause either precipitation or dissolution;injecting the fluid additive during relatively long-term fluidcirculation operations to preferentially modify the permeability offracture zones that receive relatively large portions of the total flow.

Yet further, there is provided a method to achieve even flow infractures distributed across two or more stages of a borehole havingvertical and horizontal sections, the method including: step a—selectinga horizontal section of a borehole in a reservoir containing a naturalresource; wherein the selected horizontal section defines a length andhas a series of perforation stages; step b—defining a plurality of nclusters along the entire length of the selected horizontal section,wherein each cluster has a series of perforation; step c—determining thepressure drop for a cluster in the plurality; step d—optimizing thepressure drop for the cluster selected in step c; and, step e—repeatingsteps c. and d, for each cluster in the plurality whereby the pressuredrop for the selected horizontal section is optimized. Moreover, thereis provide this method: wherein n is from 2 to 100; wherein n is from 10to 50; wherein n is greater than 5; wherein n is greater than 10;wherein n is greater than 50; and wherein one or more of the steps isrepeated at least 3 times

Still further, there is provided these methods, plans, wells and systemshaving one or more of the following features: wherein the naturalresource is a hydrocarbon; wherein the natural resource is an oil;wherein the natural resource is a geothermal resource; and wherein thelength is from about 50 feet to about 5,000 feet.

Moreover, there is provided an optimized well plan for perforating aborehole in a reservoir containing a natural resource, the optimizedwell plan obtained by a method to achieve even flow in fracturesdistributed across two or more stages of a borehole having vertical andhorizontal sections, the method including: selecting a horizontalsection of a borehole in a reservoir containing a natural resource;wherein the selected horizontal section defines a length and has aseries of perforation stages; defining a plurality of clusters along thelength of the selected horizontal section, wherein each cluster has aseries of perforation, determining the pressure drop for a cluster;optimizing the pressure drop for the cluster; and, optimizing thepressure drop for the selected horizontal section.

Still further, there is provided these methods, plans, wells and systemshaving one or more of the following features: a method for completing awell in a reservoir contain a natural resource including: obtaining anoptimized well plan, perforating a borehole in the reservoir as providedin the optimized well plan; and, wherein the natural resource isselected from the group consisting of a hydrocarbon source, crude oil,natural gas, and a geothermal energy source.

Still additionally, there is provided a method of recovering resourcefrom a well in a reservoir containing a natural resource including:producing the natural resource from the a well completed, at least inpart, based upon: an optimization well plan; or one of theseoptimization well plans.

In addition, there is provided an optimized well plan for perforating aborehole in a reservoir containing a natural resource, the optimizedwell plan obtained by a method to achieve even flow in fracturesdistributed across two or more stages of a borehole having vertical andhorizontal sections, the method including: step a—selecting a horizontalsection of a borehole in a reservoir containing a natural resource;wherein the selected horizontal section defines a length and has aseries of perforation stages; step b—defining a plurality of n clustersalong the entire length of the selected horizontal section, wherein eachcluster has a series of perforation; step c—determining the pressuredrop for a cluster in the plurality; step d—optimizing the pressure dropfor the cluster selected in step c; and, step e—repeating steps c. andd. for each cluster in the plurality; whereby the pressure drop for theselected horizontal section is optimized.

Still further, there is provided a method of obtaining even flow infractures to improve thermal sweep efficiency and mitigate thermalbreakthrough based, at least in part, on a limited entry effect, themethod including: selecting a field including a well connectedhydraulically by fractures to one or more offset wells, wherein thewells are in the earth and are associated with in a natural resourcecontaining reservoir in the earth; calculating a limited entryperforation pressure drop in an injection well, based at least in parton the flow rates expected during long-term fluid circulation throughthe system; determining a configuration of perforation clusters toachieve a limited entry effect that results in even flow distributionover all fracture zones, regardless of heterogeneity in transmissivityof each fracture zone.

Yet additionally, there is provided, a method of improving thermal sweepefficiency the method including: determining a fracture spacing designedto improve thermal sweep efficiency and mitigate thermal breakthrough;wherein a fracture half-spacing is equal to the characteristic distanceof investigation of a temperature transient for a characteristic timeequal to the project lifetime.

Still further, there is provided these methods, plans, wells and systemshaving one or more of the following features: a wherein fracture spacingis reduced, thereby reducing the mass flow rate within each fracture,wherein thermal sustainability is provided; wherein fracture intensityis increased, thereby reducing the mass flow rate within each fracture,wherein thermal sustainability is provided; wherein the system hasequipment selected from the group consisting of distributed networks,distributed fiber optic networks, pressure sensors, acoustic sensors,temperature sensors, smart well systems, intelligent completions,distributed temperature fiber optics, and distributed acoustic sensingfiber optics; including obtaining data from equipment selected from thegroup consisting of distributed networks, distributed fiber opticnetworks, pressure sensors, acoustic sensors, temperature sensors, smartwell systems, intelligent completions, distributed temperature fiberoptics, and distributed acoustic sensing fiber optics; and, including:obtaining data from equipment selected from the group consisting ofdistributed networks, distributed fiber optic networks, pressuresensors, acoustic sensors, temperature sensors, smart well systems,intelligent completions, distributed temperature fiber optics, anddistributed acoustic sensing fiber optics; and using the obtained datato in part select a perforation placement, a fracture plan, or both.

Still further, there is provided injecting a heat recovery fluid intoone or more of these wells, systems, or a well or system made accordingto one or more of these methods or plans, flowing the injected heatrecovery fluid out of perforations in an injector well and into a payzone of a geothermal resource containing formation; wherein the fluidhis heated by the formation; flowing the heated working fluid into aproduction well and, to the surface of the earth where the heat from theheated fluid is recovered and used to generate electricity.

Additionally, there is provided the method of generating electricity byoperating one or more of these wells, systems, or a well or system madeaccording to one or more of these methods or plans.

Further, there is there is provided the method of generating electricityby operating one or more of these wells, systems, or a well or systemmade according to one or more of these methods or plans, wherein theflow of the working fluid through the formation between the injectionwell and the production well has a uniform temperature front.

Accordingly, there is provided these systems, plans, methods and wellshaving one or more of the following features: the limited entry effectis taken advantage of to cause even distribution of flow and uniformfracture propagation during the stimulation phase as well as todistribute flow evenly across all fractures during the post-stimulationproduction phase; the perforation cluster design considers the flowingconditions during both the stimulation and long-term production phase;even flow in fractures to improve thermal sweep efficiency and mitigatethermal breakthrough is achieved based on the limited entry effect bydistributed flow evenly across all fractures in the system; proppants,including 40 mesh, 70 mesh, 100 mesh, microproppant (sub-100 mesh, 200mesh, and finer) and combinations thereof, are used to promote uniformaperture distribution among a set of fractures connecting two or morewellbores; fracture spacing is designed to improve thermal sweepefficiency and mitigate thermal breakthrough; and, the initial wellborecompletion program is designed to incorporate subsequent refracturing toimprove thermal sweep efficiency.

Accordingly, there is provided these systems, plans, methods and wellshaving one or more of the following features: wherein a field testprocedure describes a method to determine the injectivity of a hydraulicstimulation treatment stage as a pre-characterization step directlybefore the treatment; wherein a field testing procedure describes amethod to characterize the potential for splay fractures to propagatefrom the tips of preexisting natural fractures; and wherein fieldtesting procedure describes a method to characterize the potential forpropagating fractures to terminate against or propagate throughpreexisting natural fractures.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a schematic perspective view of an embodiment of a geothermalsystem in accordance with the present inventions, showing aperture sizeof the fractures.

FIG. 1B is a schematic perspective view of the embodiment of thegeothermal system of FIG. 1B showing a thermal front.

FIG. 1C is a chart showing flow rate for fractures in an embodiment of asystem in accordance with the present inventions.

FIG. 1D is a chart showing relative flow rates for the system of FIG.1C.

FIG. 2A is a schematic perspective view of an embodiment of a geothermalsystem using limited entry perforation in accordance with the presentinventions, showing aperture size of the fractures.

FIG. 2B is a schematic perspective view of the embodiment of thegeothermal system of FIG. 1B showing a thermal front.

FIG. 2C is a chart showing flow rate for fractures in an embodiment of asystem using limited entry perforation in accordance with the presentinventions.

FIG. 2D is a chart showing relative flow rates for the system of FIG.2C.

FIG. 3A is a schematic perspective view of a geothermal system inaccordance with the present inventions showing aperture size.

FIG. 3B is a schematic perspective view of the system of FIG. 3A showingproppant mass distribution.

FIG. 4A is a schematic perspective view of a geothermal system inaccordance with the present inventions showing aperture size.

FIG. 4B is a schematic perspective view of the system of FIG. 4A showingmicroproppant mass distribution.

FIG. 5 is a chart a production well temperature for two different wellsover a 20-year reservoir lifetime, in accordance with the presentinventions.

FIG. 6 is a perspective partial cutaway view of a geothermal system inaccordance with the present inventions.

FIG. 7 is a perspective partial cutaway view of a geothermal system inaccordance with the present inventions.

FIG. 8 is a flow chart of a stimulation process in accordance with thepresent inventions.

FIGS. 9A and 9B are cross sectional views of an injection well showingan embodiment of the limited entry perforation affects in accordancewith the present inventions.

FIG. 10 is a cross sectional view of a tubular of an injection wellshowing an embodiment of the limited entry perforation process.

FIG. 11 is a cross sectional view of an embodiment of a limited entryperforation geothermal system in accordance with the present inventions.

FIGS. 12A to 12D are charts showing the progression of a hydraulicfracture treatment over time, in accordance with the present inventions.

FIG. 13 is a chart comparing stress properties of a formation over timeduring hydraulic fracturing, in accordance with the present inventions.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

In general, the present invention relates to embodiments of systems,methods and configurations for wellbores connected hydraulically by oneor more fracture zones in subsurface resource containing reservoirs,such as geothermal reservoirs. In particular, some embodiments aregenerally directed to control flow distribution among fractures, andbetween wells, addressing heterogeneities in fracture hydraulicproperties; and providing predetermined control of resource extraction,e.g., geothermal energy, in these subsurface reservoirs.

In general, embodiments of the present inventions are directed toreal-time adjustments to hydraulic stimulation treatment procedure basedon characterization of reservoir properties, with application to oil andgas, geothermal, and mining activities. These embodiments includemethods of operating wells to improve and enhance the recovery ofresources for the earth, based at least in part, on using hydraulicstimulation plans developed from real-time monitoring and adjustment ofhydraulic stimulation activities. These embodiments have application togeothermal activities and to oil and gas activities, such aswaterflooding, steam flooding, steam assisted gravity drainage, andenhanced oil recovery.

Embodiments of the present inventions have application to geothermalenergy activities, where thermal energy is extracted from subsurfaceformations by circulating a working fluid, such as water, brine, orcarbon dioxide, through the formation and recovering the heated fluid.Embodiments of the present invention are directed toward systems,methods and configurations to control and manage fluid flow, heat flowand both, between wellbores connected hydraulically by fractures orzones of fractures in subsurface formations.

Although the focus of the present specification is toward heat flows,geothermal reservoirs, geothermal wells, geothermal energy systems andgeothermal energy management and production, as well as the recovery ofhydrocarbons, the present inventions can have applications to recoverother subterranean resources, such as minerals, ores and water.

The commercial viability of a geothermal power system depends on thelong-term thermal sustainability of the reservoir. Thermal energyrecovery efficiency is defined as the amount of heat recovered over thelifetime of a project relative to the initial amount of heat in place.Thermal breakthrough is defined as the time at which the temperature ofthe produced fluid has dropped by a threshold amount, which iscontrolled by the rate at which the thermal front propagates through thereservoir. The present invention relates to methods to design geothermalreservoir systems to control heat recovery efficiency and thermalbreakthrough to improve the system's thermal sustainability.

In general, embodiments of the present well configurations have one,two, three, four or more wells. These wells can be vertical, verticalwith horizontal section, vertical with sloped section, branchedconfigurations, comb configurations, combinations and variations ofthese, and other configurations known to or later developed by the artand combinations and variations of these. These wells can have a TVD offrom about 1,000 feet (ft) to about 20,000 ft, from about 2,000 ft toabout 10,000 ft, from about 1,000 ft to about 5,000 ft, from about 2,000ft to about 15,000 ft, greater than 1,000 ft, greater than 2,000 ft,less than 15,000 ft, less than 25,000 ft and all values within theseranges, as well as larger and smaller values. These wells can have MDfrom about 1,000 feet (ft) to about 25,000 ft, from about 2,000 ft toabout 10,000 ft, from about 1,000 ft to about 5,000 ft, from about 2,000ft to about 15,000 ft, greater than 1,000 ft, greater than 2,000 ft,less than 15,000 ft, less than 25,000 ft and all values within theseranges, as well as larger and smaller values.

In a pay zone, i.e., the section of the reservoir in the formationcontaining the sought-after natural resource (e.g., geothermal heatenergy, hydrocarbons, etc.), the borehole can have a diameter of fromabout 2 inches (″) to about 16″, about 2″ to about 10″, about 4 W, about5″, about 5½″, about 7⅝″ about 9⅜″, and all sizes within these ranges,as well as, larger and smaller diameters. It should be understood thatin a cased well, the tubular that is adjacent to, or closest to, theborehole wall, i.e. the outer most tubular, will have an outsidediameter that is the same as, or smaller than, the diameter of theborehole, such as, in the situation where there is cement between theouter most tubular and the borehole wall.

In an embodiment, the wells have perforations and stimulations thatprovide for substantially uniform flow across all of the perforations ina producing section of the well. Thus, the pay zone of the formation hasone, two, three, four or more boreholes. One or more, and preferably allof these boreholes have producing sections. These producing sections canbe from about 20 ft to about 150 ft, about 50 ft to about 200 ft, about100 ft to about 350 ft, about 50 ft to about 250 ft, about 20 ft toabout 300 ft in length, and combinations and variations of these, aswell as greater lengths. These producing sections have perforations, andcan have an average number of perforations per length of about 1.5/ft toabout 0.025/foot.

In a preferred embodiment these producing sections have one, two, three,four, five, six or more stages. A stage is a section of the producingsection that has perforations, typically each stage is separated by asection of the borehole with no perforations, i.e., a non-perforatedsection. These non-perforated sections can be from about 5 ft to about10 ft, about 10 ft to about 25 ft, and about 2 ft to about 20 ft, andcombinations and variations of these. The non-perforated sections can bethe same or different lengths in a producing section. The perforationsin a stage can have from 2 to 100 or more perforations, from about 5 toabout 10, from about 10 to about 20, from about 20 to about 40, andcombinations and variations of these, and larger numbers. The spacingfor the perforations in each stage, can be from about 2 ft to about0.025/ft, about 0.5/ft, about 0.4 ft, about 0.8 ft, about 1/ft, about0.1/ft to about 0.5/ft, about 0.3/ft to about 0.8/ft, about 1/ft. toabout 0.25/ft and combinations and variations of these, as well as,larger and smaller spacings. The stages can have the same or differentnumber of perforations and spacing of the perforations. The perforationsin each stage, or in a cluster, can be arranged around the circumferenceof the borehole, which can be referred to as the phasing of theperforations, or phasing. Thus, the orientation around the borehole,e.g., degrees around the borehole can be varied, e.g., from 0° to 90° to180° to 270° to 0°, and thus, any point around 360°. These variationsaround the circumference of the borehole can be the same or differentfor each stage. The length of each stage can be from about from about 5to about 10, from about 10 to about 20, from about 20 to about 40, fromabout 25 ft to about 100 ft, and combinations and variations of these,as well as, longer distances.

In embodiments the production sections have from 5 to 10, 5 to 50, 5 to25, 10 to 30, 15 to 40, 25 to 60, 2 to 50, more than 10, more than 20,more than 30 stages and combinations and variations of these as well aslarger and smaller numbers.

In a preferred embodiment the perforation orientation is 60° phasing,which would be shots that are spaced evenly around the borehole. In anembodiment the perforations orientation is zero degree phasing where allthe perforations in a cluster are oriented the same, for example, allaimed in one direction, e.g., all aimed up or all aimed down. Inembodiments where control or monitoring lines are installed, e.g., fiberoptic cables are installed permanently, for example in the cement behindcasing, the orientation of the clamps holding the fiber bundle to thecasing are mapped with magnetic sensors along the length of thehorizontal well prior to perforating, and then zero degree phasing isused to shoot on the opposite side of the fiber cable.

The perforations in a stage may also be placed in clusters. Aperforation cluster is a series of perforations placed along arelatively short interval of the wellbore at a specific point along thewellbore or in a stage. A typical perforation cluster is about 6 feetlong, with a total of five to ten perforation shots distributed aroundthe circumference of the wellbore at specific phasing angles and alongthe cluster interval. The cluster can be from about 1 foot to 25 feet,about 1 foot to 10 feet, about 2 feet to 12 feet, about 4 feet to 15feet, and combinations and variations of these, as well as longerlengths. A cluster can have one, two, three, four, five, ten, fifteen,from one to twenty or more shots in them. The spacing for the clustersin each stage, can be from about 2 ft to about 0.025/ft, about 0.5/ft,about 0.4 ft, about 0.8 ft, about 1/ft, about 0.1/ft to about 0.5/ft,about 0.3/ft to about 0.8/ft, about 1/ft. to about 0.25/ft andcombinations and variations of these, as well as, larger and smallerspacings. The spacing of the clusters, as well as the number ofperforations in each cluster, can be the same or different each clusterand for each stage.

Embodiments of geothermal systems, wells and producing sections, inaccordance with the present inventions, can have one or more of theseforgoing features relating to the number and spacing of boreholes,production sections, stages, non-perforated sections, perforations,clusters and combinations and variations of these.

Embodiments of the producing section of the well, in embodiments of thepresent geothermal systems, have flow across at least 80%, at least 85%,at least 90% of the perforations that is uniform and preferably highlyuniform. By “uniform flow” it is meant that the perforations in a givenlength have a flow that is within 10% of each other (for a given set ofpressures and flow rates). By “highly uniform” it is meant that theperforations in a given length have a flow that is within 5% of eachother (for a given set of pressures and flow rates).

Embodiments of the present wells, regardless of the flow acrossindividual perforations or stages, have flow across at least 80%, atleast 85%, at least 90%, and at least 95%, of the length of theproducing section that is uniform, and more preferably highly uniform.

Embodiments of the present wells, regardless of the flow acrossindividual perforations, have flow across at least 80%, at least 85%, atleast 90%, and at least 95%, of the length of a stage that is uniform,and more preferably highly uniform.

Embodiments of the present wells, regardless of the flow acrossindividual perforations or stages, have flow across at least 80%, atleast 85%, at least 90%, and at least 95%, of the length of the pay zonelocated between an injection well and a production well that is uniform,and more preferably highly uniform.

Embodiments of the present wells, regardless of the flow acrossindividual perforations, have flow across at least 80%, at least 85%, atleast 90%, and at least 95%, of the fractures placing an injection wellin fluid communication with a production well that is uniform, and morepreferably highly uniform.

Embodiments of geothermal systems, wells and producing sections, inaccordance with the present inventions, can have one or more of theseforgoing flows across the producing section, stages, perforations andcombinations and variations of these.

Generally, an even flow of the injection fluid (e.g., heat recoveryfluid) between the injection well and the production well result in atemperature profile between these two wells that is even, e.g., appearslinear and has a length in the same direction as the length of thewells, and preferably is parallel to the wells.

In an embodiment of the invention, even flow between the injection andproduction well in multiple fractures distributed across two or morestages is achieved by considering the arrangement of perforationgeometry along the entire lateral section of the wellbore, as opposed toa single stimulation stage only. Perforation pressure drop, whichdepends on the geometry of the perforation design and the flow rateflowing through the perforations, can be calculated as (equation 1):

${{\Delta p} = \frac{{0.8}08Q^{2}\rho}{C^{2}N^{2}D^{4}}},$

where Δp is the perforation pressure drop, Q, is the volumetric flowrate through the perforation, ρ is fluid density, C is the coefficientof discharge, N is the number of perforation shots in the cluster, and Dis the diameter of the perforations. The number of perforation shots,the shot geometry, and the perforation diameter of each cluster aretuned to promote even flow distribution across treatment stages thatwere initially isolated during stimulation. The perforation designconsiders the flow rates expected at each cluster (fracture) both duringthe stimulation treatment phase and the long-term injection, production,or circulation phase. In this manner, even flow distribution is achievedduring each individual stimulation treatment stage as well as duringlong-term injection, production, or circulation when the entire wellboreis open to flow.

Thus, turning to FIGS. 1A and 1B there is shown a schematic of fracturesalong a horizontal producing section of a borehole, having aheterogenous aperture and permeability distribution, which has not beenoptimized by a preferred embodiment of the present inventions. Turningto FIG. 1A, there is shown a prospective schematic representation of ageothermal system 100 having an injection well 101 and a production well102. Each having production zones 101 a, and 102 a, respectively, whichare horizontal. A fluid is injected down well 101 into the formation190, which has a pay zone 191 having high temperature rock. A series offractures (schematically represented by shaded rectangles 111, 112, 113,114, 115, 116, 117, 118, 119, 120, 121) provide a fluid connection,e.g., fluid communication, fluid conductivity, between the injectionwell 101 and the production well 102. In this manner the fluid flowsdown the injection well 101 through the fractures, where it is heated,and into the production well 102. The heated fluid then flows upproduction well 102 to the surface where thermal recovery and electricalenergy generation equipment (not show) use the recovered thermal energyto generate electricity. The shading of the graph 150 corresponds to theshading of the rectangles 111, et. seq., and illustrates their variousaperture sizes.

Turning to FIG. 1B, the same geothermal system 100, as shown in FIG. 1Ais depicted, except in this figure the shading illustrates thetemperature of the formation and the fluid as it moves through thefractures. Thus, because of the heterogenous nature of the fractures,the temperature profile, or front, (shown by dashed line 150), isnon-uniform, not even, and not linear or straight. This non-uniformityresults in uneven remove of heat, causing thermal breakthrough, andother deleterious conditions, that shorten the life of the geothermalsystem, and adversely affect the economics and efficiency of theproduction of electricity by the system.

FIGS. 1C and 1D show graphs for another geothermal system, which has notbeen optimized by a preferred embodiment of the present inventions. Thissystem, as did the system of FIGS. 1A and 1B has a series of fractures(ten for the system of FIGS. 1C and 1D) that have a heterogenousdistribution and flow properties. FIG. 1C shows the individual flowrates for each fracture, and FIG. 1D shows the relative flow rates foreach fracture as a percentage of the total flow across the pay zonebetween the injection well and production well. These flow rates willresult in an uneven and non-uniform flow profile and thermal front, andthe resulting detrimental effects caused by these.

Through embodiments of the optimization of perforations, stages andstage features, hydraulic fracturing and proppant use, and combinationsand variations of this, a substantially uniform, and preferably evenflow distribution, and temperature profile, across the productionsection, and thus thermal energy recovery, can be obtained andmaintained in a geothermal system. Obtaining this flow and temperatureprofile across the production section can be maintained for 1 to 20years and longer. This flow across the production zone provides one ormore, and in embodiments all of the following advantages and benefits:(i) enables the above ground systems to be built to, or specified for, aspecific and predetermined flow and temperature of the heated fluidprovided by the production well; (ii) the geothermal system can maintainthis specific and predetermined flow and temperature of the heated fluidfor extended periods of time, e.g., 2 to 20 years, 5 to 20 years, morethan 10 years, 20 years and more, and combinations and variations ofthese; (iii) it provides for greater predictability in managing the flowof the fluid and to modify or intervene the downhole wellbore andfracture connections to improve flow distribution over time; (iv) itprevents thermal breakthrough; (v) it increases the efficacy of the heatextraction and the overall geothermal system; (vi) it extends theoperable life of the geothermal system; and, (vii) it avoids costlyrebuilds or system changes to address declines in thermal energy beingrecovered from the production well, e.g., temperature of the fluiddeclining over time; to name a few.

Turning to FIGS. 2A and 2B there is shown a schematic of the geothermalsystem of FIG. 1A, except in this embodiment the flow profile along theproduction section has been optimized to provide a uniform flow andtemperature profile 150 a through the pay zone 191, along the entirelength of production zones 101 a, 102 a. Thus, FIG. 2B shows a uniformtemperature front 150 a for the geothermal system 100. It is noted thatthe aperture area for each of the fractures is still heterogeneous, andhas the same heterogeneity as in the embodiment of FIGS. 1A and 1B.However, the flow and temperature profile 150 a across the pay zone inFIG. 2B is even, and substantially different from, and improved over theunoptimized flow and temperature profile 150 of FIGS. 1B. An embodimentof this type of optimization to the system is referred to a limitedentry perforation (“LEP”), e.g., where the configuration of perforationsis used to correct and optimize flow characteristics.

Turning to FIGS. 2C and 2D there is shown graphs for another geothermalsystem, which has been optimized by an LEP embodiment of the presentinventions. This system, as did the system of FIGS. 2A and 2B has aseries of fractures (ten for the system of FIGS. 2C and 2D) that have aheterogenous distribution and flow properties. However, because thewells were built using LEP the actual flows across these fractures isvery uniform. FIG. 2C shows the individual flow rates for each fracture,and FIG. 2D shows the relative flow rates for each fracture as apercentage of the total flow across the pay zone between the injectionwell and production well. For this LEP geothermal system the individualflow rates across all of the fractures has a difference of less than10%. (Put another way, the difference in flow between all of thefractures in the production zone is less than 10%.).

In an embodiment, even flow in fractures to improve thermal sweepefficiency and mitigate thermal breakthrough is achieved based on thelimited entry effect (“LEP”). This embodiment is directed at a systemconsisting of one well connected hydraulically by fractures to one ormore offset wells, e.g., production wells, where an objective is torecover and produce thermal energy from a subsurface formation. Thelimited entry perforation pressure drop in the injection well iscalculated based on the flow rates expected during long-term fluidcirculation through the system; the perforation clusters are designed toachieve a limited entry effect that results in even flow distributionover all fracture zones, regardless of heterogeneity in transmissivityof each fracture zone. The rate of propagation of the thermal frontwithin each fracture zone is dominated by the fluid mass flow ratethrough each zone, therefore even distribution of flow will result in acontrolled thermal front propagation.

In an embodiment, proppants are used to promote and maintain uniformaperture distribution among the hydraulic fractures. In embodiments theproppants can have a size, (diameter or longest cross section) of fromabout 30 mesh to about 200 mesh, 40 mesh, 40/60 mesh, 70 mesh, 70/100mesh, 100 mesh, 100/150 mesh, 200 mesh, 200/220 mesh, 250 mesh, 250/260mesh, and combinations and variations of these. The term“microproppants” as used herein means any proppant that has a sizesmaller than 100 mesh, i.e., sub-100 mesh, and includes 200 mesh, 300mesh and finer proppants. These proppants are used to promote uniformaperture distribution among a set of fractures connecting two or morewellbores (e.g., injection and production wells). Proppant is injectedas a slurry of water, chemicals, and proppant material during thestimulation treatment. The pressure from the hydraulic fluid opens up,e.g., fractures, the formation. As the pressure is reduced and thefractures close, a proppant pack is formed, keeping the fractures open,and allowing for improved flow conditions to be maintained for asignificant period of time following the stimulation treatment. The useof proppant promotes a uniform distribution of fracture aperture andpermeability, resulting in improved, optimized, controlled, andcombinations and variations of these, thermal front propagation.

As used herein, unless specified otherwise, mesh size and mesh can becorresponded to the relative diameters as set forth in Table 1. As usedherein, unless specified otherwise: if particles are described as havinga mesh size of “A” it means that the particles will pass through thatmess, but will be stopped by a smaller mesh size; if particles aredescribed as having a mesh size of + (plus) mesh “A” it means that theparticles will sit upon (e.g., be stopped by) the mesh “A” screen orsieve; and, if particles are described as being − (minus) mesh “A” itmeans that the particles will pass through (e.g., not be stopped by) themesh “A” screen or sieve. When particle sizes, for a sample of proppants(a few 100 proppants, to thousands of proppants, to millions ofproppants, to tons of proppants) are described as “A”/“B”, “A” denotesthe largest size of the distribution of sizes, and “B” denotes thesmallest size of the distribution of sizes. Thus, a sample of proppantsbeing characterized as mesh 20/40 would have proppants that will passthrough a 20 mesh sieve, but will not pass through (i.e., are caught by,sit a top) a 40 mesh sieve.

TABLE 1 U.S. Mesh Microns Millimeters (i.e., mesh) Inches (μm) (mm) 30.2650 6730 6.730 4 0.1870 4760 4.760 5 0.1570 4000 4.000 6 0.1320 33603.360 7 0.1110 2830 2.830 8 0.0937 2380 2.380 10 0.0787 2000 2.000 120.0661 1680 1.680 14 0.0555 1410 1.410 16 0.0469 1190 1.190 18 0.03941000 1.000 20 0.0331 841 0.841 25 0.0280 707 0.707 30 0.0232 595 0.59535 0.0197 500 0.500 40 0.0165 400 0.400 45 0.0138 354 0.354 50 0.0117297 0.297 60 0.0098 250 0.250 70 0.0083 210 0.210 80 0.0070 177 0.177100 0.0059 149 0.149 120 0.0049 125 0.125 140 0.0041 105 0.105 1700.0035 88 0.088 200 0.0029 74 0.074 230 0.0024 63 0.063 270 0.0021 530.053 325 0.0017 44 0.044 400 0.0015 37 0.037

Generally, the proppants can be any material synthetic or natural thatcan withstand the pressure, temperature and other downhole conditions ofthe well. The proppants can be any volumetric shape, for example, balls,spheres, squares, prolate spheroids, ellipsoids, spheroids, eggs, cones,rods, boxes, multifaceted structures, and polyhedrons (e.g.,dodecahedron, icosidodecahedron, rhombic triacontahedron, and prism), aswell as, other structures or shapes.

Spherical type structures are examples of a preferred shape forproppants. Sphere and spherical shall mean, and include unless expresslystated otherwise, any structure that has at least about 90% of its totalvolume within a “perfect sphere,” i.e., all points along the surface ofthe structure have radii of equal distance. A “spherical type” structureshall mean, and include all spheres, and any other structure having atleast about 70% of its total volume within a perfect sphere.

The proppants can be any of the sizes set forth on Table 1, as well as,all sizes within the range of that Table, and larger and smaller sizesas well.

Turning to FIGS. 3A and 3B there is provided a prospective schematicview of a geothermal system 301, which has not been optimized by apreferred embodiment of the present inventions. In FIG. 3A thefractures, e.g., 310, are located along the length of injection well305. The grey scale of the fractures corresponds to the grey scale ofthe bar chart 320, providing the total aperture size in inches for thefractures. Bar chart 320 is in units of inches. The proppant is 100mesh. The formation has a matrix permeability of 0.1 millidarcy (“md”).

In FIG. 3B, the mass distribution of the proppant in the fractures isshown by the grey scale for the fractures, e.g., 312, corresponding tobar chart 322. Bar chart 322 is in units of total mass per area(lbs/ft²). In this embodiment the settling effect of the proppant (e.g.,much greater mass per area on the lower sides, or bottom, of thefractures) is observable. This settling effect can further significantlyaffect the fracture aperture distribution, in an adverse manner. Ingeothermal wells, this settling effect generally has two primarynegative consequences: (i) flow is constricted to a relatively smallportion of the overall fracture, creating much higher flowing velocitiesand therefore cooling the system faster; and, (ii) providing relativelysmall heat transfer surface area for heat conduction from the rocksurrounding the fracture to flow into the fluid being advected withinthe fracture, which leads to faster cooling.

Thus, FIG. 3B provides an illustration of an embodiment of a set offractures created during hydraulic stimulation treatment. Thedistribution of fracture aperture and proppant density are shown. Thisexample demonstrates behavior for a case where 100 mesh proppant is usedduring the stimulation treatment (injected at a concentration of 3pounds/gal at 80 barrels per minute) in a low-permeability formationaccording to the prior art. The proppant settling effect causes asignificant portion of the fracture to close reducing the effectivenessof the stimulation.

Turning to FIGS. 4A and 4B there is provided a prospective schematicview of a geothermal system 401, which has been optimized by a preferredembodiment of the present inventions. In FIG. 5A the fractures, e.g.,410, are located along the length of injection well 405. The grey scaleof the fractures corresponds to the grey scale of the bar chart 420,providing the total aperture size in inches for the fractures. Bar chart420 is in units of inches. The proppant is 200 mesh, and thus isconsidered a microproppant. The formation has a matrix permeability of0.1 md. In FIG. 4B, the mass distribution of the proppant is shown bythe grey scale for the fractures, e.g., 412, corresponding to bar chart422. Bar chart 422 is in units of total mass per area (lbs/ft²). In thisembodiment the settling effect of the proppant is greatly reduced by theuse of a microproppant. Further, the use of the microproppant providesimproved distribution of fracture aperture (compared to the distributionof FIG. 4A)

Thus, FIG. 4B provides an illustration of an embodiment of a set offractures created during hydraulic stimulation treatment. Thedistribution of fracture aperture and proppant density are shown. Thisexample demonstrates behavior for a case where 200 mesh proppant is usedduring the stimulation treatment (injected at a concentration of 3pounds/gal at 80 barrels per minute) in a low-permeability formationaccording to the present invention. The use of microproppant inhibitsthe proppant settling effect, resulting in a more even and fulldistribution of proppant at the end of the treatment.

In an embodiment, fracture spacing is designed to improve thermal sweepefficiency and mitigate thermal breakthrough. Fracture spacinginfluences heat mining efficiency; fracture half-spacing should be equalto the characteristic distance of investigation of a temperaturetransient for a characteristic time equal to the project lifetime.However, reducing fracture spacing (or increasing the fractureintensity) can result in a reduction in the mass flow rate within eachfracture, which can have a positive impact on thermal sustainability.

In an embodiment, the initial wellbore completion program is designed toincorporate subsequent refracturing to improve thermal sweep efficiency.Uneven fracture spacing is utilized in the initial hydraulic stimulationtreatment. The spacing is such that much of the unfractured rock remainsat ambient temperature conditions up until the point at whichrefracturing is required. The refracturing treatment targets the zonesthat have remained hot. The fracture zones stimulated originally may ormay not be isolated following the refracturing treatment.

The commercial viability of a geothermal power system depends on, amongother things, the long-term thermal sustainability of the reservoir.Thermal energy recovery efficiency is defined as the amount of heatrecovered over the lifetime of a project relative to the initial amountof heat in place. Thermal breakthrough is defined as the time at whichthe temperature of the produced fluid has dropped by a threshold amount,which is controlled by the rate at which the thermal front propagatesthrough the reservoir. Embodiments of the present invention relates tomethods to design geothermal reservoir systems to control heat recoveryefficiency and to mitigate thermal breakthrough to improve the system'sthermal sustainability, among other things.

Heat recovery from a geothermal resource is influenced both by heatconduction in relatively impermeable rocks and advection of heat that iscarried within fluid flowing through fractures. Geothermal reservoirmanagement strategies commonly involve reinjecting fluid for thepurposes of maintaining reservoir fluid pressures (and thereforeminimizing declines in production flow rates) and for improving heatsweep efficiencies. Generally, the reinjection wells are connectedhydraulically with the nearby production wells to achieve the beneficialeffects of reinjection. However, a common challenge, both inconventional hydrothermal settings and enhanced geothermal systems, isthat fluid that is reinjected can tend to concentrate alonghigh-permeable channels, thereby causing early or prematurebreakthrough. Early breakthrough can have negative consequences, mostnotably by causing significant declines in production fluid temperatureand energy content. Moreover, once a strong flow channel develops, otherless permeable channels are bypassed, resulting in suboptimal heat sweepof the subsurface reservoir. Subsurface porous and fractured media isinherently heterogeneous, therefore variability in the permeability offlow channels is common. In oil and gas settings, similar negativeconsequences related to early breakthrough have been documented in waterflooding projects, enhanced oil recovery projects, and steam-assistedgravity drainage projects. Therefore, a challenge and long standingproblem in geothermal reservoir engineering is the ability to create astrong hydraulic connection between injection and production wells whileat the same time ensuring that early breakthrough effects are minimized.Embodiment of the present invention address, mitigate and overcome thislong standing problem.

Limited Entry Perforation Techniques

Objectives of perforating a lengthy cased-and-cemented wellbore sectionfor fracture stimulation are, among other things, to enable extensivecommunication with the reservoir and control the allocation of fluid andproppant into multiple intervals as efficiently as possible duringfracturing treatments. Simultaneously treating multiple intervalsreduces the number of fracturing stages required, thus reducingtreatment cost. Perforating for hydraulic fracturing normally involvesthe use of a shaped-charge jet perforator conveyed by a hollow-steelcarrier. In horizontal wells, perforating is typically accomplished, forexample, by pumping a wireline conveyed, select-fire jet perforating gunstring into the lateral section of the well along with a bridge plug.This process is known as “plug-and-perf” and is generally successful inestablishing adequate connections from the perforations to the hydraulicfractures.”

Due to variability in the rock strength properties at different pointsalong the wellbore, the pressure required to initiate and/or propagate afracture may vary across different perforation clusters, even within asingle treatment stage. The limited entry technique overcomes thischallenge and encourages uniform growth of the fractures created at eachperforation cluster during a hydraulic stimulation treatment. Thelimited entry method takes advantage of a friction pressure drop throughan orifice (i.e., the perforations). The Bernoulli theorem provides atheoretical basis for estimating perforation friction pressure drop as afunction of the flow rate through the perforation cluster and theperforation cluster design parameters (shape of perforations, number ofperforation shots, and size of the perforation holes):

${{\Delta p} = \frac{{0.8}08Q^{2}\rho}{C^{2}N^{2}D^{4}}},$

where Δp is the perforation pressure drop, Q, is the volumetric flowrate through the perforation, ρ is fluid density, C is the coefficientof discharge, N is the number of perforation shots in the cluster, and Dis the diameter of the perforations (all parameters are in consistentunits).

For example, an embodiment of a treatment stage length would range from100 ft to 300 ft. Treatment flow rates typically range from about 10barrels per minute (bpm) up to about 100 bpm. The number of perforationclusters per stage can range from one per stage, 3 per stage, 5 perstage, 9 per stage, 15 per stage, from 2 to 20 per stage, andcombinations and variations of these as well as higher numbers. Thisprovides cluster or fracture spacing on the order of 10 ft to 100 ft.Proppant concentrations typically range from 1 to 3 pounds of proppantper gallon of fluid (ppg), larger and smaller concentrations may beutilized. The number of perforation shots per perforation cluster mayrange from about 4 to 12 (typically around 2 to 4 perforation shots perfoot) and combinations and variations of these, as well as larger andsmaller numbers. Perforation hole diameter typically ranges, forexample, from 0.25 in to 0.5 in, with 0.3 in to 0.4 in being typical.

Generally, the perforations and the hydraulic fracturing and stimulationtreatments are performed on, or through, the injection wells. Theproduction well in addition to having openings to receive the heatedworking fluid, may also have hydraulic fracturing and stimulationtreatments conducted through it. In embodiments at least one of thewells is hydraulically fractured (typically the injector in thepreferred embodiment). The production wells may be openhole, orcased/cemented and fractured.

Perforation Friction Pressure Drop

Many processes can result in uneven flow distribution among a set offractures intersecting a wellbore, both during hydraulic fracturing andduring long-term production operations. These processes are usuallycaused by heterogeneity in rock properties. For example, variability inthe magnitude of the minimum principal stress along the wellbore cancause each perforation cluster interval to experience a differentfracture propagation pressure, enabling certain fracture zones to growmore easily and therefore take flow more easily. Variability in thetensile strength or fracture toughness cause by lithology changes orgeneral heterogeneity can have similar effects. During long-term fluidcirculation between two wellbores for the purpose of geothermal energyrecovery, variability in the fracture aperture can have a significantimpact on the flow distribution among multiple fracture zones.

Even in the hypothetical case where fracture flow properties are assumedto be homogeneous, pipe friction pressure losses alone can cause unequalflow distribution. Generally it is theorized that, in some instances,flow tends to concentrate in fractures closest to the heel of the wells(i.e., the first few fractures encountered along the flow path). For acase where the two wellbores have a 7 in wellbore diameter and areconnected with a set of 10 fractures, the first fracture receives 36% ofthe total volumetric flow rate, the second fracture receives 18% of theflow, the third fracture receives 11% of the flow, and the flowdistribution continues to decrease for the remainder of the fractures,while the tenth fracture receives roughly 5% of the flow. For casesassuming smaller wellbore diameters, thereby increasing pipe frictionpressure effects, the uneven flow distribution can be even more found tobe more pronounced.

Embodiments of the limited entry perforation systems address this lossfor flow by increasing, preferably in a progressive manner, the numberof perforations, the size of the perforations, and combinations andvariations of these, as the stages move further from the heel of thewell.

Interstage LEP Design

The long standing problems of thermal breakthrough and short circuit areaddressed, mitigated and overcome by the use of, among other things,interstage limited entry perforation techniques, which is to design theset of perforation clusters so that they encourage a perforationfriction pressure drop sufficient to distribute flow evenly both betweena subset of clusters within a single treatment stage (under the flow andwellbore conditions expected during a hydraulic fracture treatmentstage) and amongst perforation clusters across multiple stages (underthe flow and wellbore conditions expected during long-term operations)and combinations and variations of these.

In a preferred embodiment of the invention, the interstage LEP designwould be optimized for a 1500 ft horizontal wellbore divided into 5treatment stages with 3 perforation clusters per treatment stage. Inthis case, each stage is 300 ft long, and the perforation clusterspacing (and therefore fracture spacing) is 100 ft. The target maximumfluid injection rate during the hydraulic stimulation treatment is 60barrels per minute for each stage and the maximum proppant concentrationis 3 pounds per gallon. The target fluid injection rate during long-termfluid circulation operations is 100 barrels per minute. The targetminimum perforation friction pressure drop during the hydraulic fracturetreatment is 1000 psi, and the target minimum perforation frictionpressure drop during the long-term fluid circulation phase is 450 psi.

A perforation diameter of 0.325 in is chosen, and the perforationclusters are created with 5 shots per cluster. A perforation shapefactor of 0.75 is assumed. In this case, the perforation frictionpressure drop during hydraulic fracturing is 6068 psi, and the pressuredrop during long-term fluid circulation operations is 522 psi. Thisdesign achieves the target minimum friction pressure drop during boththe fracturing treatment phase and the long-term fluid circulationphase. This design could be executed relatively simply in practicebecause each perforation cluster is the same.

Another preferred embodiment of the invention involves optimizing theLEP design for the same conditions as described above. In this case, aperforation diameter of 0.25 in is chosen and a perforation shape factorof 0.75 is assumed. A tapered distribution of perforation shots percluster is chosen, where the clusters in the stage closest to the toe(Stage 1) each have 7 shots per cluster, Stages 2, 3, and 4 each have 8shots per cluster, and Stage 5 has 4 shots per cluster, and Stage 5 has9 shots per cluster. This design results in perforation friction dropsfor each stage ranging from 459 psi to 758 psi during the hydraulicfracture treatment phase and ranging from 5333 psi to 8816 psi duringthe long-term fluid circulation phase. This design would tend toencourage more flow to divert toward to stages closer to the toe. Thepressure drops are within ranges that can be achieved with typicalfracturing pressure pumps.

Real-Time Characterization of Hydraulic Fractures

In an embodiment field tests are performed to determine the injectivityof a hydraulic stimulation treatment stage as a characterization step,for example, for other treatments. In a preferred embodiment the initialstep is a pre-characterization steps before a main treatment step, e.g.,a hydraulic stimulation, having one, two, three, four or more pumpings.One or more sections, or stages, of the borehole can be isolated usingzonal isolation technology. The pre-characterization steps can becarried out on each of these simultaneously or serially.

The pre-characterization tests can involve among other things: a testingprocedure to characterize the potential for splay fractures to propagatefrom the tips of preexisting natural fractures; the potential forpropagating fractures to terminate against or propagate throughpreexisting natural fractures; the potential for other types offracturing; the potential for conductivity of the reservoir. Thepre-characterization tests are used for planning the later stimulationtreatment. The process of pre-characterization and stimulation treatmentcan be repeated multiple times until the desired well, formation,fracture zone properties and conditions are obtained.

In an embodiment the pre-characterization tests are performed on astage-by-stage basis to characterize heterogeneity in flow propertiesalong the wellbore.

Pre-characterization tests, e.g., a pressure transient test, couldinvolve, among other things: i) a traditional constant rate injectiontest, ii) a tendency for shear stimulation test, iii) a diagnosticfracture injection test, iv) a step-rate injection test, v) astep-pressure injection test, or vi) some combination thereof.

The pre-characterization step can include performing active measures,e.g., pumping and monitoring; monitoring methods, e.g., seismic,microseismic, distributed well sensors, etc.; and computational, e.g.,modeling and analysis of historical data, and combinations and variationof these. Information and data and process that can be used in thepre-characterization test include, for example, analyzing lostcirculation zones, analyzing mudlog data, performing wellbore imagelogs, or performing wireline pressure/temperature/spinner logs.

Turning to FIGS. 12A to 12D there are shown a series of chartsillustrating the progression of a hydraulic fracture test and the test'seffects on the formation and its stress characteristics. In FIG. 12Athere is shown at time 1 hour of the stimulation test the distributionof fracture aperture 1201 a, fracture pressure 1202 a, and the temporalprofile of the well pressure 1203 a. At this point in the test thenatural fracture is beginning to pressurize, but a splay fracture hasnot yet formed.

In FIG. 12B there is shown at time ˜1.71 hour of the stimulation testthe distribution of fracture aperture 1201 b, fracture pressure 1202 b,and the temporal profile of the well pressure 1203 b. At this point inthe test the test a splay fracture has initiated, as seen in 1201 b and1202 b.

In FIG. 12C there is shown at time ˜1.72 hour of the stimulation testthe distribution of fracture aperture 1201 c, fracture pressure 1202 c,and the temporal profile of the well pressure 1203 c. At this point inthe test the test a splay fracture has initiated and begun propagating,as seen in 1201 c and 1202 c. The signature of the splay fracture isdetectable at the injection well.

In FIG. 12D there is shown at time 1.75 hour of the stimulation test thedistribution of fracture aperture 1201 d, fracture pressure 1202 d, andthe temporal profile of the well pressure 1203 d. At this point in thetest the test the splay fracture has propagated a significant distanceaway from the wellbore, as seen in 1201 d and 1202 d. The signature ofthe splay fracture is detectable at the wellbore as a pressure drop.

Turning to FIG. 13 is a chart showing the profile of induced stresschanges caused by the deformation of both the natural fracture and thepropagating splay fractures. This stress change profile represents asignal that is detected using, for example, a Distributed Strain Sensingfiber optic cable installed in the injection well. The stress change atearly time is caused by deformation of the natural fracture, whereas thestress change at 1.71 hours indicates the initiation and propagation ofthe splay fracture.

In embodiments the information obtained from pre-characterization tests,such as those illustrated in FIGS. 12 and 13, describe how to detect theinfluence of natural fractures that are in the vicinity of the wellbore.Cased/cemented well completions in geothermal applications have beendiscredited by the art because it was thought that the cement will sealoff the permeable natural fractures. Embodiments of the presentinventions go against this thinking of the prior art. Embodiments of thepresent inventions can cause hydraulic fractures to propagate away fromthe wellbore and intersect permeable natural fractures further out inthe reservoir. The hydraulic fracture and proppant system createenhanced near-wellbore flow connections to the broader reservoir system.The interaction between hydraulic and natural fractures can be called“mixed-mechanism stimulation.”

The interaction of hydraulic fractures, natural fractures, and theircombination (e.g., splay fractures) have specific signals (e.g.,pressure transient, strain, or stress) that can be used to identify thesubsurface behavior. This information can further be used to plan anddevelop completion and fracturing plans for these specific wells andformations.

Using downhole tests and signals (e.g., pressure transient or strainfrom distributed fiber optics), a perforation and fracture plan can bedeveloped and implements that improves, and preferably optimizes theperforation cluster location, stage location, and hydraulic fracturetreatment parameters based on the expected mixed-mechanism fracturingbehavior.

EXAMPLES

The following examples are provided to illustrate various embodiments ofsystems, processes, compositions, applications and materials of thepresent inventions. These examples are for illustrative purposes, may beprophetic, and should not be viewed as, and do not otherwise limit thescope of the present inventions.

Example 1

Turning to FIG. 5, there is provided a graph 500 comparing thetemperature profiles 501 of an LEP based geothermal system of thepresent invention against the temperature profile 502 of a conventionalgeothermal system, which is not based on LEP, over a 20-year period. Forthe conventional system, the pressure drop effects exhibits prematurethermal breakthrough due to rapid cooling of high-permeability fracturepathways. Thus, as seen in the profile 502, the conventional system canlose about 20° C. over the first 1.25 years (˜10% reduction intemperature), and about 35° C. (˜18% reduction in temperature). Incontrast, the case with active LEP tends to cool significantly slowerbecause flow is distributed more evenly among the set of fracturesconnecting the injection and production wells. Thus, at year 1.25 theLEP system has a temperature drop if about 2° C. (˜1% reduction intemperature); and at year 2.5 the LEP system has a temperature drop ofabout 13° C. (˜7% reduction in temperature).

The case with no LEP pressure drop effects 502 exhibits prematurethermal breakthrough due to rapid cooling of high-permeability fracturepathways. In contrast, the case with active LEP 501 cools significantlyslower because flow is distributed more evenly among the set offractures connecting the injection and production wells.

At the 20 year point, the typical end for the lifetime of a geothermalsystem, the LEP system is still about 5° C. warmer that the conventionsystem, and thus should have additional life beyond the typical 20period for conventional systems.

Example 2

Turning to FIG. 6, there is provided a perspective cross sectional viewof an embodiment of an LEP geothermal system 600. The system 600 has aninjection well 610 and a production well 615. The wells 610, 615 extendfrom the surface 602 of the earth 601, down into a formation 603, whichhas a pay zone 604. The injection well 610 has a heel 611 and ahorizontal section 612, which is also the producing section. Theproducing section 612, has stages 613 a, 613 b, 613 c, 613 d, 613 e.Each of these stages have different configurations of perforations, toaddress and level out the flow across the pay zone 604. Between thestages, the injection well has non-perforated sections 614 a, 614 b, 614c, 614 d, 614 e. The heel 611 is not perforated.

The system 600 has fracture zones 605 a, 605 b, 605 c, 605 d, 605 e inthe pay zone 604, of the formation 603, that provide fluidcommunication, e.g., flow, between the producing section 612 and theproduction well 615. One or more, and in embodiments all, of thefracture zones, 605 a, etc., have different flow characteristics, e.g.,porosity, aperture size, conductivity, permeability, and combinationsand variation of these and other factors. The producing well 615 has aheel 616, which is not perforated, and has perforations, or otheropenings, along its length in the pay zone 604, to receive the heatedfluid from the pay zone.

The system has a surface system 630, that has a heat recovery andelectricity generation system 631, a transmission system 632, and aninjection system 633.

In operation the operating fluid is forced down the injection well 610,and out of the perforations in the stages, 613 a etc., and into thefracture zones, 605 a etc., where it flows across the pay zone 604. Thefluid is heated in the pay zone 604, and then enters into the productionwell 615, where the heated fluid is transported to the heat recovery andelectricity generation system 631 on the surface 602.

As the fluid moves across the pay zone 604, in the direction of arrow617, the flow across the length of the pay zone 604 (and also across allof the fracture zones, 605 a etc.) is even, uniform, substantiallylinear, and parallel with the injection and production wells, as shownby flow line 618. This flow line 618 also represent the thermal front,which is even, uniform, substantially linear, and parallel with theinjection and production wells, for the system.

It is the positions, and number of perforations in each of the stages613 a, etc., that address, mitigate and overcome the uneven flow causedby the heterogeneity of the fractures, and the fracture zones.

Example 2A

In an embodiment of the system of Example 2, the flow rate for each ofthe stages has a difference from the flow rate of the other stages, thatis smaller than about 15%, preferably smaller than about 10% and morepreferably smaller than about 5%.

Example 2B

In an embodiment of the system of Example 2, the flow rate across thepay zone has no section where the difference in flow rate from anothersection: is greater than 15%, preferably greater than 10%, morepreferably greater than 7% and still more preferably greater than 5%.

Example 2C

In an embodiment of the system of Example 2, the flow rate for each ofthe fracture zones has a difference from the flow rate of the otherfracture zones, that is smaller than 15%, preferably smaller than 10%and more preferably smaller than 5%.

Example 2D

In the embodiments of Examples 2, 2A, 2B, and 2C, the systemadditionally utilizes proppant having a proppant size of 200/250 mesh.The proppant reduces the heterogeneity of the fracture flowcharacteristics.

Example 2E

In the embodiments of Examples 2, 2A, 2B, 2C and 2D, the systems show atemperature provide, where in the first 5 years of operation thetemperature of the heated fluid recovered from the production welldeclines less than 5° C. per year, preferably less than 2.5° C. peryear, and more preferably less than 1° C. per year.

Example 2F

In the embodiments of Examples 2, 2A, 2B, 2C and 2D, the systems show atemperature provide, where in the first 5 years of operation thetemperature of the heated fluid recovered from the production welldeclines less than 10% per year, preferably less than 5% per year, andmore preferably less than 2% C per year.

Example 2G

In the embodiments of Examples 2, 2A, 2B, 2C and 2D, the systems show atemperature provide, where in the first 2 years of operation thetemperature of the heated fluid recovered from the production welldeclines less than 5° C. per year, preferably less than 2.5° C. peryear, and more preferably less than 1° C. per year.

Example 2H

In the embodiments of Examples 2, 2A, 2B, 2C and 2D, the systems show atemperature provide, where in the first 2 years of operation thetemperature of the heated fluid recovered from the production welldeclines less than 10% per year, preferably less than 5% per year, andmore preferably less than 2% C per year.

Example 2I

In the embodiments of Examples 2 and 2A to 2H, the producing section ofthe well is from 100 to 300 ft, and each stage is about 10% to about 15%of the length of the producing section. The stages have from 2 to about300 perforations, and for embodiments where clusters are utilized, 900or more perforations per stage could be utilized.

Example 3

Turning to FIG. 7, there is provided a perspective cross sectional viewof an embodiment of an LEP geothermal system 700. The system 700 has twoinjection wells 710, and 720, and a production well 715. The wells 710,720, 715 extend from the surface 702 of the earth 701, down into aformation 703, which has a pay zone 704. The injection well 710 has aheel 711 and a horizontal section 712, which is also the producingsection. The injection well 720 has a heal 721 and a horizontal section722, which is also the producing section.

The producing section 712, has stages 713 a, 713 b, 713 c, 713 d, 713 e.Each of these stages have different configurations of perforations, toaddress and level out the flow across the pay zone 704. Between thestages, the injection well has non-perforated sections 714 a, 714 b, 714c, 714 d, 714 e. The heel 711 is not perforated.

The producing section 722, has stages 723 a, 723 b, 723 c, 723 d, 723 e.Each of these stages have different configurations of perforations, toaddress and level out the flow across the pay zone 704. Between thestages, the injection well 722 has non-perforated sections 724 a, 724 b,724 c, 724 d, 724 e. The heel 721 is not perforated.

The system 700 has fracture zones 705 a, 705 b, 705 c, 705 d, 705 e inthe pay zone 704, of the formation 703, that provide fluidcommunication, e.g., flow, between the producing section 712 ofinjection well 710 and the production well 715; and between producingsection 722 of injection well 720 and the production well 715.

One or more, and in embodiments all, of the fracture zones, 705 a, etc.,have different flow characteristics, e.g., porosity, aperture size,conductivity, permeability, and combinations and variation of these andother factors. In addition, in embodiments, the section of the fracturezone adjacent to section 710 can have different flow characteristicsfrom section of the same fracture zone adjacent to section 720.

The producing well 715 has a heel 716, which is not perforated, and hasperforations, or other openings, along its length in the pay zone 704,to receive the heated fluid from the pay zone.

The system has a surface system 730, that has a heat recovery andelectricity generation system 731, a transmission system 732, and aninjection system 733.

In operation the operating fluid is forced down the injection well 710,the injection well 720, and both wells, and out of the perforations inthe stages, 713 a etc., 723 a etc., and into the fracture zones, 705 aetc., where it flows across the pay zone 704. The fluid is heated in thepay zone 704, and then enters into the production well 715, where theheated fluid is transported to the heat recovery and electricitygeneration system 731 on the surface 702.

As the fluid moves across the pay zone 704, in the direction of arrow717, and arrow 727, the flow across the length of the pay zone 704 (andalso across all of the fracture zones, 705 a etc.) is even, uniform,substantially linear, and parallel with the injection and productionwells, as shown by flow lines 718, 728. These flow lines 718, 728 alsorepresent the thermal front, which is even, uniform, substantiallylinear, and parallel with the injection and production wells, for thesystem.

It is the positions, and number of perforations in each of the stages713 a, etc., 723 a, etc., that address, mitigate and overcome the unevenflow caused by the heterogeneity of the fractures, and the fracturezones.

Example 3A

In an embodiment of the system of Example 3, the flow rate for each ofthe stages has a difference from the flow rate of the other stages, thatis smaller than about 15%, preferably smaller than about 10% and morepreferably smaller than about 5%.

Example 3B

In an embodiment of the system of Example 3, the flow rate across thepay zone has no section where the difference in flow rate from anothersection: is greater than 15%, preferably greater than 10%, morepreferably greater than 7% and still more preferably greater than 5%.

Example 3C

In an embodiment of the system of Example 3, the flow rate for each ofthe fracture zones has a difference from the flow rate of the otherfracture zones, that is smaller than 15%, preferably smaller than 10%and more preferably smaller than 5%.

Example 3D

In the embodiments of Examples 3, 3A, 3B, and 3C, the systemadditionally utilizes proppant having a proppant size of 200/250 mesh.The proppant reduces the heterogeneity of the fracture flowcharacteristics.

Example 3E

In the embodiments of Examples 3, 3A, 3B, 3C and 3D, the systems show atemperature provide, where in the first 5 years of operation thetemperature of the heated fluid recovered from the production welldeclines less than 5° C. per year, preferably less than 2.5° C. peryear, and more preferably less than 1° C. per year.

Example 3F

In the embodiments of Examples 3, 3A, 3B, 3C and 3D, the systems show atemperature provide, where in the first 5 years of operation thetemperature of the heated fluid recovered from the production welldeclines less than 10% per year, preferably less than 5% per year, andmore preferably less than 2% C per year.

Example 3G

In the embodiments of Examples 3, 3A, 3B, 3C and 3D, the systems show atemperature provide, where in the first 2 years of operation thetemperature of the heated fluid recovered from the production welldeclines less than 5° C. per year, preferably less than 2.5° C. peryear, and more preferably less than 1° C. per year.

Example 3H

In the embodiments of Examples 3, 3A, 3B, 3C and 3D, the systems show atemperature provide, where in the first 2 years of operation thetemperature of the heated fluid recovered from the production welldeclines less than 10% per year, preferably less than 5% per year, andmore preferably less than 3% C per year.

Example 3I

In the embodiments of Examples 3 and 3A to 3H, the producing section ofthe well is from 100 to 300 ft, and each stage is about 10% to about 15%of the length of the producing section. The stages have from 2 to about300 perforations, and for embodiments where clusters are utilized, 900or more perforations per stage could be utilized.

Example 4

In the construction of a geothermal energy system. The pay zone betweenthe injection well and the production well is initially fractured. Theflow characteristics base upon this initial fracture are determinedalong the length of the producing section of the well. From this initialfracture information, the number and sizes of stages, and the number,spacing and positioning of perforations, clusters and both, aredetermined and then implemented. This determination is to provide aninjection well producing section that mitigates, the observedheterogeneity in the initial fractures, and to provide an even flow fromall of the stages, and across the pay zone. The testing and then furtherperfing, fracturing and both can be repeated several times, to reachoptimum, e.g., linear, flow characteristics across the fractures and thepay zone. Proppants, preferably microproppants, can be used during thisprocess as well, to reduce the heterogeneity in the fracturesthemselves.

Example 5

Turning to FIG. 8 there is shown a flow chart of an embodiment of a 5step LEP fracturing program for a producing section having three stages(zones A, B, and C). The steps are performed in the order numbered.

Example 6

Turning to FIGS. 9A and 9B there is shown a cross schematic of ageothermal system prior to performing an LEP and after, respectively.The geothermal system has an production well 901 and a injection well902. The system has 5 stages, corresponding to fracture zones placingthe two wells in fluid communication. The flow of the fluid is shown bythe arrow from the injection well 902 to the production well 901. Priorto LEP, the stages have a flow distribution of 50%, 30%, 15%, 4% and 1%,as the stages are located further from the heel and closer to the toe ofthe well. Thus there is a difference in flow of 49% between stage 1 andstate 5 of the well prior to LEP. FIG. 9B shows the flow properties ofthe well after they have been optimized by the LEP procedure. The flowsfrom heel to tow are 22%, 21%, 20%, 19% and 18%. The greatest differencein flow is 4% across the entire length of the producing section and forall stages.

Example 7

For the injection well 902 of Example 6, FIG. 10 shows a detailed crosssectional schematic view of stages 1, 2, and 3, during an LEP procedure.Thus, the injection well 902 has a casing or tubular 1002, that hasplugs, e.g., frac-plugs, 1010, 1011, 1012, inserted within the tubular1002 to isolate the three stages, 1, 2, 3. The frac-plugs are configuredso that each of the stages can be isolated during hydraulic fracturing.The flow of the fracturing fluid would be as shown by arrow 1070 (thiswould also be the direction of flow of the working fluid duringoperation). Stage 1 has three clusters of perforations 1020, 1021, 1022,each having three perforations, e.g., 1025. Stage 2 has three clustersof perforations, 1030, 1031, 1032, each having five perforations, e.g.,1035, Stage 3 has three clusters of perforations, 1040, 1041, 1042, eachhaving seven perforations, e.g., 1045.

During operation the frac-plugs 1010, 1011, 1012 are removed, and theoperating fluid is flowed through the tubular 1002 in the direction ofarrow 1070. The flow rate of operating fluid “q” in the tubular 1002leaves flows out of each stage at a rate of q/5. The difference in theperforation clusters for each stage compensates for the differences inthe initial flow of the system (as shown in FIG. 9A) thus providing foreven flow out of each of the stages. (It being understood, that Stages4, and 5, which are not shown, would have increasing numbers ofperforations, to provide for the uniform flow rate of q/5 for all fivestages.)

Example 8

Turning to FIG. 11 there is shown a cross sectional view of a geothermalsystem where the limited entry perforation method is implemented. Thesystem has an injection well 1112 and a production well 1111 that extendbelow the surface 1130 of the earth into a pay zone of a formation. Thesystem has five stages, 1101, 1102, 1103, 1104, 1105. The stages areconfigured for the limited entry perforation effect, such as for examplethe configuration of Example 10. The system has an even, uniform, andlinear flow and temperature front across the pay zone between theproducing sections of the injection and production wells. This even flowand temperature front is also maintained over time. The flow andtemperature front is shown by line 1020 a at time t₁, and is shown byline 1020 b at time t₂, where t₂ is greater than t₁.

Example 9

In one embodiment of the invention, a field test procedure describes amethod to determine the injectivity of a hydraulic stimulation treatmentstage as a pre-characterization step directly before the treatment. Atreatment stage is isolated using zonal isolation technology. The stageis completed with multiple perforation clusters. A pressure transienttest is performed to characterize the injectivity of the stage prior topumping the stimulation treatment. The pressure transient test couldinvolve i) a traditional constant rate injection test, ii) a tendencyfor shear stimulation test, iii) a diagnostic fracture injection test,iv) a step-rate injection test, v) a step-pressure injection test, orvi) some combination thereof. The pre-characterization tests areperformed on a stage-by-stage basis to characterize heterogeneity inflow properties along the wellbore.

Example 10

In one embodiment of the invention, a field testing procedure describesa method to characterize the potential for splay fractures to propagatefrom the tips of preexisting natural fractures. Natural fracturesintersecting the wellbore are characterized during drilling or prior toinstallation of the casing; this step can be done, for example, byanalyzing lost circulation zones, analyzing mudlog data, performingwellbore image logs, or performing wireline pressure/temperature/spinnerlogs. Distributed strain sensing fiber optics are installed in thewellbore behind casing. Prior to performing a stimulation treatment, azone that has been previously identified to have intersected a naturalfracture is isolated and perforated. Pressure in the zone is elevated toa level that causes the natural fracture to slip. The pressure transientis analyzed to determine whether a splay fracture formed off the tip ofthe natural fracture. The distributed strain sensing data is interpretedfor signatures of a splay fracture. One or more tests is performed tocharacterize the overall tendency for splay fracturing to occur in theformation.

Example 11

In one embodiment of the invention, a field testing procedure describesa method to characterize the potential for propagating fractures toterminate against or propagate through preexisting natural fractures.Natural fractures intersecting the wellbore are characterized duringdrilling or prior to installation of the casing; this step can be done,for example, by analyzing lost circulation zones, analyzing mudlog data,performing wellbore image logs, or performing wirelinepressure/temperature/spinner logs. A fracture with sufficientinclination relative to the borehole is selected. A section of thewellbore is isolated with packers at a location offset from the naturalfracture at a distance sufficient that a propagating fracture wouldlikely intersect the natural fracture at some distance away from thewellbore. Fluid is pumped into the isolated section of the wellbore atrates and pressures sufficient to initiate and propagate a fracture awayfrom the well. The pressure transient is analyzed to identify thesignature of the propagating fracture intersecting, arresting against,or propagating through the natural fracture. The distributed strainsensing data is interpreted for signatures of the propagating fractureintersecting, arresting against, or propagating through the naturalfracture. One or more tests is performed to characterize the overalltendency for propagating fracture to terminate against natural fracturesin the formation.

Example 12

A geothermal well system has an injector well and a production well. Theinjection well having 15 stages along a lateral producing section. Theinjection well having a casing cemented in place into the formation. Thecasing and cement being perforated. The injection well and theproduction well are in fluid communication with each other through anetwork of mixed-mechanism fractures in the formation. The injection ofthe working fluid will flow the mixed-mechanism fractures, and proppantif present, and be heated.

Example 13

The geothermal well of Example 12 can have any of the competitiondesigns, e.g., stagers, clusters, phasing, proppant size, etc., andcombinations and variations of these, that are set forth in thisspecification.

Example 14

A geothermal field having well system that has from 2 to 10 productionwells and from 1 to 4 injector wells associated with, and in fluidcommunication with, a production well. The injection wells having from 3to 20 stages along lateral producing sections. The injection wellshaving a casing cemented in place into the formation. The casing andcement being perforated. The injection wells and their associatedproduction well are in fluid communication with each other through anetwork of mixed-mechanism fractures in the formation. The injection ofthe working fluid will flow the mixed-mechanism fractures, and proppantif present, and be heated.

Example 15

A geothermal field having from 1 to 10 vertical production wellsextending from the surface into a pay zone. The vertical productionwells have associated with them and are in fluid communication withinjection wells. One, two, or more injection wells are associated and influid communication with the production wells.

It being understood that in embodiments of systems and wells theinjection well, the production well, and both can have the same ordifferent orientations and these orientations may vary along the lengthof the well. These orientations, in the pay zone, can be vertical, on anangle from vertical, to and including horizontal, can have orientationsranging from 0° i.e., vertical, to 90°, i.e., horizontal and greaterthan 90° e.g., such as a heel and toe and combinations of these such asfor example “U” and “Y” shapes. These wells may further have segments orsections that have different orientations, they may have straightsections and arcuate sections and combinations thereof; and for example,may be of the shapes commonly found when directional drilling isemployed.

Example 16

A geothermal field having from 1 to 10 production wells extending fromthe surface into a pay zone. These production wells have horizontalsections in the pay zone. The horizontal sections of the productionwells have associated with them and are in fluid communication withvertical injection wells. One, two, or more of the vertical injectionwells are associated and in fluid communication with the productionwells.

Example 17

The geothermal well of Examples 2, 3, 14, 15 and 16 can have any of thecompetition designs, e.g., stagers, clusters, phasing, proppant size,etc., and combinations and variations of these, that are set forth inthis specification.

Example 18

A geothermal well system, such as for example the geothermal well systemof Examples 2, 3, and 12-17, can have sensors and monitors associatedwith the system. These sensors and monitors can be downhole, surface, inmonitoring wells and combinations and variations of these. These sensorsand monitors can measure and record real time conditions of the wellsuch as seismic, acoustic, pressure and temperature as various locationsalong the well, in the reservoir and both. These sensors and monitorscan be devices and systems such, distributed fiber optic networks, smartwell systems, intelligent completions, distributed temperature fiberoptics, and distributed acoustic sensing fiber optics, and combinationsand variations of these, to name a few. The sensors and monitors, e.g.,distributed fiber optics, can be permanently fixed into the well, suchas in the cement, they can be temporarily placed in the well, such as bya wire line and both.

In an embodiment of an intelligent completion incorporates permanentdownhole sensors and surface-controlled downhole flow control valves,that monitor, evaluate, and actively manage production, injection andboth, in real time without any well interventions. Data is transmittedto surface for local or remote monitoring in preferably a digital wellcontrol platform.

The intelligent completion, or other sensing and monitoring systems andequipment are used to obtain data and information, as well as accesshistoric data, top provide information to develop perforation andfracture plans, to fine tune or enhance perforation and fracture plans,to rework wells, and to change perforation and fracture plans as a wellsystem is reworked, completed and both.

HEADINGS AND EMBODIMENTS

It should be understood that the use of headings in this specificationis for the purpose of clarity, and is not limiting in any way. Thus, theprocesses and disclosures described under a heading should be read incontext with the entirely of this specification, including the variousexamples. The use of headings in this specification should not limit thescope of protection afford the present inventions.

The various embodiments of systems, compositions, articles, uses,applications, equipment, methods, activities, and operations set forthin this specification may be used for various other fields and forvarious other activities, uses and embodiments. Additionally, theseembodiments, for example, may be used with: existing systems,compositions, articles, uses, applications, equipment, methods,activities, and operations; may be used with systems, compositions,articles, uses, applications, equipment, methods, activities, andoperations that may be developed in the future; and with such systems,compositions, articles, uses, applications, equipment, methods,activities, and operations that may be modified, in-part, based on theteachings of this specification. Further, the various embodiments andexamples set forth in this specification may be used with each other, inwhole or in part, and in different and various combinations. Thus, theconfigurations provided in the various embodiments and examples of thisspecification may be used with each other. For example, the componentsof an embodiment having A, A′ and B and the components of an embodimenthaving A″, C and D can be used with each other in various combination,e.g., A, C, D, and A. A″ C and D, etc., in accordance with the teachingof this Specification. Thus, the scope of protection afforded thepresent inventions should not be limited to a particular embodiment,example, configuration or arrangement that is set forth in a particularembodiment, example, or in an embodiment in a particular Figure.

The invention may be embodied in other forms than those specificallydisclosed herein without departing from its spirit or essentialcharacteristics. The described embodiments are to be considered in allrespects only as illustrative and not restrictive.

1. A method of providing optimized recovery of geothermal energy for aformation while reducing thermal breakthrough, the method comprising: a.selecting a formation below the surface of the earth, the formationcomprising a geothermal heat source; b. selecting a first well and asecond well in the formation; wherein each well has a vertical sectionand a non-vertical section; c. hydraulically fracturing the formation bypumping a fracturing fluid under pressures in excess of the fracturepressure of the formation through a plurality of perforations in a sidewall in the non-vertical section of the first well, the second well orboth wells; d. whereby a substantially uniform tortuous flow path isestablished between the first well and the second well; wherein thesubstantially uniform tortuous flow path can transmit more than 40 Kg/s(kilograms of fluid/second) of a heat recovery fluid from the first wellto the second well.
 2. The method of claim 1, wherein the plurality ofperforations comprises: a first stage having from 3 to about 20perforations, and a second stage having from 3 to about 20 perforations.3. The method of claim 1, wherein the pumping pressure is less than 90%of the fracture pressure and the flow rate is from about 40 Kg/s toabout 100 Kg/s.
 4. The method of claim 2, wherein the pumping pressureis less than 90% of the fracture pressure and the flow rate is fromabout 40 Kg/s to about 100 Kg/s.
 5. The method of claim 1, wherein theplurality of perforations comprises: a first stage having from 3 toabout 20 perforations, and a second stage having from 3 to about 20perforations, wherein the number of perforations in the second stage isdifferent from the number of perforations in the first stage.
 6. Themethod of claim 1, wherein the fracture fluid comprises a proppant.
 7. Alimited entry perforation (LEP) geothermal energy system, the systemcomprising: a. a first well extending from above a surface of the earthinto the earth and into a formation containing a geothermal heat source;b. a second well extending from above the surface of the earth into theearth and into the formation containing a geothermal heat sourcedefining a geothermal reservoir; c. the first well having a heel and ahorizontal producing section, wherein the horizontal producing sectioncomprises a casing and extends into the geothermal reservoir; d. thesecond well extending into the geothermal reservoir; e. a producingsection of the first well comprising a plurality of stages, wherein eachstage comprises a plurality of perforations through the casing and intothe geothermal reservoir; f. a plurality of fracture zones in thegeothermal reservoir placing the stages of the first well in fluidcommunication with the second well, at least one of the fracture zonesassociated with at least one of the stages of the producing section ofthe first well; g. wherein the associated fracture zone defining atortuous fluid flow path for a heat recovery fluid through thegeothermal reservoir; and, h. whereby the configuration of theperforations and the fracture zones provide a substantially uniform flowpath between the producing section and the second well.
 8. The system ofclaim 7, wherein the perforations in at least one of the stages is zerophased.
 9. The system of claim 7, wherein the perforations in at leastone of the states is 60° phased.
 10. The system of claim 7, wherein theplurality of perforations in each of the stages defines a cluster; 11.The system of claim 7, wherein the first well is an injection well; 12.The system of claim 7, wherein the fracture zones comprise a pluralityof proppants.
 13. The system of claim 12, wherein the proppants define aproppant pack.
 14. The system of claim 7, wherein the proppants comprisemicroproppants.
 15. The system of claim 13, wherein the proppant packcomprises a monolayer distribution of the proppant in the fractures. 16.The system of claim 7, wherein a majority of each the fracture zoneshave a different flow characteristic.
 17. The systems of claim 7,wherein the perforations in each of a majority of the stages define aflow different flow characteristic, whereby a majority of the stageshave a different flow characteristic.
 18. The system of claim 7, whereinthe substantially uniform flow is characterized in part by having a flowacross at least 85% of the perforations that is uniform.
 19. (canceled)20. (canceled)
 21. (canceled)
 22. (canceled)
 23. (canceled) 24.(canceled)
 25. (canceled)
 26. (canceled)
 27. (canceled)
 28. A wellsystem for the recovery of geothermal energy, the system comprising: a.an injection well in a geothermal reservoir below a surface of theearth; b. a producing well in the geothermal reservoir; c. a fluid flowpath through the geothermal reservoir and placing the injection well andthe producing well in fluid communication, whereby the system isconfigured to flow a heat recovery fluid from the injection well throughthe reservoir and into the producing well; d. the fluid flow pathcomprising a plurality of fracture zones, wherein a majority of thefracture zones have different flow characteristic; and, e. the injectionwell comprising a plurality of stages, wherein each of the stages has apredetermined perforation pattern, wherein the predetermined perforationpattern is based in part upon the flow characteristics of the fracturezones; f. whereby the system provides for a uniform temperature front ofa heat recovery fluid through the reservoir between the injection welland the production well.
 29. A method to achieve even flow in fracturesdistributed across two or more stages of a borehole having vertical andhorizontal sections, the method comprising: a. selecting a horizontalsection of a borehole in a reservoir containing a natural resource;wherein the selected horizontal section defines a length and comprises aseries of hydraulic fracture treatment stages; b. defining a pluralityof perforation clusters along the length of the selected horizontalsection, wherein each perforation cluster has a series of perforationholes that cause a friction pressure drop when fluid flows through; c.optimizing the friction pressure drop across each cluster within anindividual treatment stage based on the flow conditions during thehydraulic fracturing treatment; and d. optimizing the friction pressuredrop across each perforation cluster along multiple treatment stagesbased on the flow conditions during long-term operations.
 30. (canceled)31. A method to achieve even flow in fractures distributed across two ormore stages of a borehole having vertical and horizontal sections, themethod comprising: a. selecting a horizontal section of a borehole in areservoir containing a natural resource; wherein the selected horizontalsection defines a length and comprises a series of perforation stages;b. defining a plurality of n clusters along the entire length of theselected horizontal section, wherein each cluster has a series ofperforation; c. determining the pressure drop for a cluster in theplurality; d. optimizing the pressure drop for the cluster selected instep c; and, e. repeating steps c. and d. for each cluster in theplurality f. whereby the pressure drop for the selected horizontalsection is optimized.
 32. The method of claim 31, wherein the naturalresource is a hydrocarbon.
 33. (canceled)
 34. The method of claim 31,wherein the natural resource is a geothermal resource. 35-56. (canceled)